2019 Annual Report
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Natural Resource Partners L.P.
1201 Louisiana Street, 34th Floor
Houston, Texas 77002
www.nrplp.com
Natural Resource Partners L.P.
2019 Financial Highlights
Unitholder Information
(in thousands, except per unit)
2019
2018 (1)
2017
2016
2015
For the Years Ended December 31
Total revenues and other income
Asset impairments
Income (loss) from operations
Net income (loss) from continuing operations
Net income from continuing operations
excluding impairments
$ 263,935
$
$
$
148,214
51,321
(25,414)
$ 122,800
Net income (loss) from discontinued operations
$
956
Net income (loss)
$ (24,458)
Per common unit amounts (basic)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Per common unit amounts (diluted)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Distributions paid per common unit
Average number of common
units outstanding - basic
Average number of common
units outstanding - diluted
Net cash provided by (used in)
Operating activities of continuing operations
Investing activities of continuing operations
Financing activities of continuing operations
Free cash flow (2)
Cash flow cushion (2)
Distributable cash flow (2)
Adjusted EBITDA (2)
$
$
$
$
$
$
$
(4.43)
0.08
(4.35)
(4.43)
0.08
(4.35)
2.65
12,260
12,260
$
$
137,319
8,221
$ (253,305)
$ 139,040
$
7,762
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
278,512
$ 246,325
$ 279,244
$ 300,635
18,280
192,538
122,360
140,640
17,687
140,047
7.35
1.42
8.77
5.90
0.86
6.76
1.80
12,244
20,234
178,282
7,607
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,967
176,559
82,485
85,452
6,182
88,667
4.57
0.50
5.06
3.68
0.28
3.96
1.80
12,232
21,950
$
$
$
$
$
$
$
$
$
$
$
$
$
15,861
181,157
90,626
$
378,327
$ (170,699)
$ (260,443)
106,487
$ $117,884
6,266
$
(311,277)
96,892
$ (571,720)
7.28
0.50
7.78
7.28
0.50
7.78
1.80
12,232
12,232
$
$
$
$
$
$
$
(20.80)
(24.94)
(45.75)
(20.80)
(24.94)
(45.75)
2.70
12,232
12,232
112,151
9,807
$
$
80,243
65,057
$
$
144,907
15,805
(6,839)
$ (134,149)
$ (146,373)
$ (166,443)
183,440
16,080
121,324
$
75,970
9,248
$ (29,444)
$
$
$
144,210
(8,339)
157,815
$ 144,933
$ 383,980
$ 199,228
$
230,241
121,958
211,483
$
255,172
$ 235,273
$ 240,553
$
$
$
$
$
Cash, cash equivalents and restricted cash
$
98,265
$ 206,030
26,980
$
39,171
$
40,244
Total assets
$ 1,085,907
$ 1,341,647
$ 1,389,164
$ 1,448,649
$ 1,674,865
Current portion of long-term debt, net
Long-term deb, net
Long-term lease obligations (3)
Class A convertible preferred units
Partners’ capital
$
45,776
$ 470,422
$
3,506
$ 164,587
$ 338,963
$
$
$
$
$
115,184
$
79,740
$
140,037
$
80,745
557,574
$ 729,608
$ 990,234
$ 1,130,696
—
164,587
423,481
$
$
$
—
173,431
265,211
$
$
$
—
—
151,530
$
$
$
—
—
76,336
(1) On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, and all the related amendments to all open contracts using
the modified retrospective method. NRP recognized a $70.5 million cumulative effect of adoption adjustment in the opening balance of partners’ capital on January 1, 2018. Comparative
information for the years ended December 31, 2017, 2016 and 2015 have not been restated and continues to be reported under the standards in effect for those periods.
(2) See “—Non-GAAP Financial Measures” in this Annual Report on Form 10-K form more information.
(3) On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments and recognized assets and liabilities on its Consolidated Balance
Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months.
Partnership Headquarters
1201 Louisiana Street
Suite 3400
Houston, TX 77002
713-751-7507
Regional Offices
Coal and Hard Minerals
5260 Irwin Road
Huntington, WV 25705
Investor Relations
Tiffany Sammis
1201 Louisiana Street
Suite 3400
Houston, TX 77002
713-751-7515
Email: info@nrplp.com
Stock Exchange
Our units are listed on the
New York Stock Exchange
under the symbol NRP.
Independent Auditors
Ernst & Young LLP
5 Houston Center
1401 McKinney St, Suite 2400
Houston, TX 77010
Transfer Agent and Registrar
American Stock Transfer
and Trust Company
Client Operations
6201 15th Avenue
Brooklyn, NY 11219
Website: www.astfinancial.com
Email:help@astfinancial.com
800-937-5449
Website
www.nrplp.com
Information regarding Natural Resource Partners L.P. is located on the partnership’s
website. On the site is operational and financial information as well as all SEC filings and
our corporate governance documents, including our Code of Business Conduct and Ethics,
our Corporate Governance Guidelines and Board of Directors’ Audit Committee Charter.
Requests for copies of the annual report or other data may be made through the website or
by contacting Investor Relations. These requests will be provided free of charge.
Contact NRP Board
We have established procedures for contacting the non-management members of the
NRP Board of Directors. To communicate any concerns or issues to the Board of Directors,
please direct any correspondence to:
Chairman of the CNG Committee
NRP Board of Directors
1201 Louisiana Street, Suite 3400
Houston, TX 77002
888-252-2396
Schedule K-1
Unitholders receive Schedule K-1 packages that summarize their allocable share of the
partnership’s reportable tax items for the calendar year. Generally, these K-1s are available
on NRP’s website no later than mid-March. Unitholders should refer questions regarding
their Schedule K-1 to the following:
Natural Resource Partners L.P.
Tax Package Support
P.O. Box 799060
Dallas, TX 75379-9060
Fax: 1-866-554-3842
Toll Free: 1-888-334-7102
Forward-Looking Statements
Statements included in this annual report 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
COVID-19, capital expenditures and acquisitions, expected commencement dates of
mining, projected quantities of future production by our lessees producing from our
reserves, and projected demand or supply for coal, trona and soda ash that will affect
sales levels, prices and royalties realized by us.
These forward-looking statements speak only as of the date hereof and are made based
upon management’s current plans, expectations, estimates, assumptions and beliefs
concerning future events impacting us and therefore involve a number of risks and
uncertainties, including uncertainties surrounding the COVID-19 pandemic. 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. Please read “Item
1A. Risk Factors” of the Form 10-K for important factors that could cause our actual results
of operations or our actual financial condition to differ.
To Our Unitholders
Natural Resource Partners L.P.
2019 Annual Report
2019 was a year filled with much volatility in the coal space and financial markets.
The year began with strong metallurgical coal pricing, open financial markets, steady
distributions from our soda ash business and overall positive sentiment, but as the year
progressed sentiment turned bearish with depressed thermal coal markets and weakened
metallurgical export markets, a reduction in distributions from our soda ash business,
relatively closed financial markets and multiple lessee bankruptcies. Moving into 2020,
we are currently focused on navigating the evolving impact of COVID-19 that has locked
down the global economy and significantly lowered energy demand, while also working
through the bankruptcy of our largest lessee, Foresight Energy. Despite these strong
headwinds, impressive achievements made in 2019 have better positioned us to face
the challenges that lie ahead.
2019 Accomplishments:
•
Reduced our outstanding debt by $163 million
• Refinanced and extended $300 million of long-term debt to 2025
• Extended the maturity of our $100 million revolving credit facility to 2023
• Generated $139 million in Free Cash Flow
•
•
Resolved our only outstanding major litigation, winning in every respect
with no liability to NRP
Continued quarterly common unit distributions of $0.45 per unit and paid
a one-time special distribution of $0.85 per unit to our common unitholders
to cover unitholder tax liability on the gain from the sale of our construction
aggregates business in 2018
Despite these strong headwinds,
impressive achievements made in 2019
have better positioned us to face the
challenges that lie ahead.
1
Business Highlights
Our Coal Royalty segment generated 82% of the partnership’s Revenues and Other Income
and 85% of the partnership’s Free Cash Flow in 2019. While there was a decline in metallurgical
and thermal coal pricing in the second half of 2019, we believe our lessees locked in higher
sales prices from the beginning of the year which minimized the negative effects of depressed
pricing in the latter half of 2019. Also, I’d like to highlight we positively navigated multiple
lessee bankruptcies in 2019, a continued and encouraging track record of NRP’s history at
minimizing loss in the lessee bankruptcy process and ensuring economic mines emerge
with relatively minimal impact to the long-term earnings power to NRP.
Our Soda Ash segment received $32 million in distributions from Ciner Wyoming in 2019.
Ciner Wyoming, of which we own a 49% equity interest, reached multiple production
records in 2019 and continues to be one of the largest and lowest cost natural soda ash
producers in the world.
We remain laser
focused on cash and
liquidity during this
time of uncertainty
and believe we have
ample resources to
navigate these difficult
circumstances for the
foreseeable future.
Looking Ahead
It is evident through our ability to navigate the turbulent markets and multiple lessee
bankruptcies, that the numerous transformative steps taken in recent years to right-size
our business, fortify our financial position and streamline our cost structure have better
positioned us to face the headwinds of 2020, including the ongoing uncertainty
surrounding the COVID-19 pandemic.
Our COVID-19 response started with prioritizing the health and safety of our employees,
which included transitioning to working remotely from home and ensuring each employee
is healthy and set up to work as efficiently as in the office. This transition went seamlessly,
and we continue to operate safely and effectively. The coal landscape is evolving quickly
due to COVID-19 with many operators temporarily idling operations. We are maintaining
regular contact with our lessees to stay informed, understand the financial impact to us
and minimize risks to our business. We remain laser focused on cash and liquidity during
this time of uncertainty and believe we have ample resources to navigate these difficult
circumstances for the foreseeable future.
We know there are many headwinds facing the partnership as we enter into 2020, but with
$98 million of cash on hand, $100 million of availability on our revolver and five years before
our parent company bonds mature, we believe we will weather this storm while continuing to
reduce debt and meet our financial obligations. Thank you to the many unitholders who have
been through the highs and lows with us. We will continue to strive to create partnership
value for our unitholders.
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
2
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2019 or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 1-31465
NATURAL RESOURCE PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
35-2164875
(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)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Units representing limited partner interests
Trading Symbol(s)
NRP
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
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
No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes
No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company,
or an emerging growth company. See definition of "accelerated filer", "large accelerated filer", "smaller reporting company," and "emerging
growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
Accelerated Filer
Non-accelerated Filer
Smaller Reporting Company
Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes
No
The aggregate market value of the common units held by non-affiliates of the registrant on June 28, 2019, was $318 million based on a closing
price on that date of $35.46 per unit as reported on the New York Stock Exchange.
Documents incorporated by reference: None.
Table of Contents
Items 1. and 2. Business and Properties
TABLE OF CONTENTS
PART I
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
PART II
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Signatures
Financial Statements and Supplementary Data
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors and Executive Officers of the Managing General Partner and Corporate Governance
PART III
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Exhibits, Financial Statement Schedules
PART IV
1
23
37
38
38
39
39
44
59
60
101
101
103
104
110
118
120
127
130
133
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Table of Contents
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
Statements included in this 10-K 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, and other natural resources; estimated revenues, expenses
and results of operations; projected production levels by our lessees; Ciner Wyoming LLC’s ("Ciner Wyoming's") trona mining
and soda ash refinery operations; distributions from our soda ash joint venture; 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 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 this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our
actual financial condition to differ.
ii
Table of Contents
PART I
As used in this Part I, 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. NRP Finance
Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes due
2025 (the "2025 Senior Notes").
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Partnership Structure and Management
We are a publicly traded Delaware limited partnership formed in 2002. We own, manage and lease a diversified portfolio of
mineral properties in the United States, including interests in coal and other natural resources and own a non-controlling 49%
interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining and soda ash production business.
Our business is organized into two operating segments:
Coal Royalty and Other—consists primarily of coal royalty properties and coal-related transportation and processing assets.
Other assets include industrial mineral royalty properties, aggregates royalty properties, oil and gas royalty properties and timber.
Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Northern Powder River Basin in the United States.
Our industrial minerals and aggregates properties are located in various states across the United States, our oil and gas royalty
assets are primarily located in Louisiana and our timber assets are primarily located in West Virginia.
Soda Ash—consists of our 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining and soda ash production
business located in the Green River Basin of 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.
Our operations are conducted through Opco and our operating assets are owned by our subsidiaries. NRP (GP) LP, our general
partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a
limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations and the Board of
Directors and officers of GP Natural Resource Partners LLC make decisions on our behalf. Robertson Coal Management LLC, a
limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource
Partners LLC. Subject to the Board Representation and Observation Rights Agreement with certain entities controlled by funds
affiliated with The Blackstone Group Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management
LP (collectively referred to as "GoldenTree"), Mr. Robertson, Jr. is entitled to appoint the members of the Board of Directors of
GP Natural Resource Partners LLC and has delegated the right to appoint one director to Blackstone.
The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited
Partnership or Quintana Minerals Corporation, which are companies controlled by Mr. Robertson, Jr. These officers allocate varying
percentages of their time to managing our operations. Neither our general partner, GP Natural Resource Partners LLC, nor any of
their affiliates receive any management fee or other compensation in connection with the management of our business, but they
are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.
We have regional offices through which we conduct our operations, the largest of which is located at 5260 Irwin Road,
Huntington, West Virginia 25705 and the telephone number is (304) 522-5757. Our principal executive office is located at 1201
Louisiana Street, Suite 3400, Houston, Texas 77002 and our telephone number is (713) 751-7507.
1
Table of Contents
Segment and Geographic Information
The amount of 2019 revenues and other income from our two operating segments is shown below. For additional business
segment information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
—Results of Operations" and "Item 8. Financial Statements and Supplementary Data—Note 8. Segment Information" in this
Annual Report on Form 10-K, which are both incorporated herein by reference.
(In thousands)
Coal Royalty and Other
Soda Ash
Total
Coal Royalty and Other Segment
Amount
% of Total
$
$
216,846
47,089
263,935
82%
18%
100%
Our coal reserves are primarily located in the Appalachia Basin, the Illinois Basin and the Northern Powder River Basin in
the United States. We lease our reserves to experienced mine operators under long-term leases. Approximately two-thirds of our
royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for
additional terms. Leases include the right to renegotiate royalties and minimum payments for the additional terms. We also own
and manage coal-related transportation and processing assets in the Illinois Basin that generate additional revenues generally based
on throughput or rents. As described in the "—Other Coal Royalty and Other Segment Assets" section below, we also own oil and
gas, industrial minerals and aggregates reserves that generate a portion of the Coal Royalty and Other segment revenues.
Under our standard royalty lease, we grant the operators the right to mine and sell our reserves in exchange for royalty
payments based on the greater of a percentage of the sale price or fixed royalty per ton of minerals mined and sold. Lessees calculate
royalty payments due to us and are required to report tons of minerals mined and sold as well as the sales prices of the extracted
minerals. Therefore, to a great extent, amounts reported as royalty revenues are based upon the reports of our lessees. We periodically
audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections
to verify that the information that our lessees have submitted to us is accurate. Our audit and inspection processes are designed to
identify material variances from lease terms as well as differences between the information reported to us and the actual results
from each property.
In addition to their royalty obligations, our lessees are often subject to minimum payments, which reflect amounts we are
entitled to receive even if no mining activity occurs during the period. Minimum payments are usually credited against future
royalties that are earned as minerals are produced. In certain leases, the lessee is time limited on the period available for recouping
minimum payments and such time is unlimited on other leases.
Because we do not operate any coal mines, our coal royalty business does not bear ordinary operating costs and has limited
direct exposure to environmental, permitting and labor risks. Our lessees, as operators, are subject to environmental laws, permitting
requirements and other regulations adopted by various governmental authorities. In addition, the lessees generally bear all labor-
related risks, including retiree health care costs, black lung benefits and workers’ compensation costs associated with operating
the mines on our coal and aggregates properties. We pay property taxes on our properties, which are largely reimbursed by our
lessees pursuant to the terms of the various lease agreements.
2
Table of Contents
Coal Reserves and Production Information
The following table presents coal reserves information as of December 31, 2019 for the properties that we own by major
coal region:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
Total Appalachia Basin
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total
Proven and Probable Reserves (1)
Underground
Surface
Total
301,742
720,378
57,881
1,080,001
299,818
—
—
1,379,819
3,031
242,379
19,794
265,204
5,074
163,555
1,957
435,790
304,773
962,757
77,675
1,345,205
304,892
163,555
1,957
1,815,609
(1)
In excess of 90% of the reserves presented in this table are currently leased to third parties.
The following table presents the type of our coal reserves by major coal region as of December 31, 2019:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
Total Appalachia Basin
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total
Type of Coal
Thermal
Metallurgical (1)
Total
243,939
545,949
58,554
848,442
304,892
163,555
1,875
60,834
416,808
19,121
496,763
—
—
82
304,773
962,757
77,675
1,345,205
304,892
163,555
1,957
1,318,764
496,845
1,815,609
(1) For purposes of this table, we have defined metallurgical coal reserves as reserves located in seams that historically have
been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the
metallurgical category can also be used as thermal coal.
3
Table of Contents
The following table presents the sulfur content and the typical quality of our coal reserves by major coal region as of
December 31, 2019:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
Total Appalachia Basin
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total
Compliance
Coal (2)
Low
(<1.0%)
Sulfur Content
Typical Quality (1)
Medium
(1.0%
to
1.5%)
High
(>1.5%)
Total
Heat
Content
(Btu per
pound)
Sulfur
(%)
46,307
443,313
43,382
533,002
—
—
82
46,507
677,143
47,905
771,555
1,002
257,264
46,384
2,590
304,773
962,757
77,675
306,238
1,345,205
239,230
27,180
267,412
—
2,152
302,740
163,555
1,957
—
—
—
—
304,892
163,555
1,957
533,084
937,067
269,564
608,978
1,815,609
12,977
13,238
13,405
13,189
11,476
8,800
6,964
2.61
0.91
0.96
1.30
3.29
0.65
0.69
(1) Unless otherwise indicated, the coal quality information in this Annual Report and on the Form 10-K is reported on an as-
received basis with an assumed moisture of 6% for Appalachia Basin reserves, and site specific moisture values for Illinois
(typically 12% moisture) and Northern Powder River Basin (typically 25% moisture).
(2) Compliance coal, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu and meets the sulfur dioxide
emission standards imposed by Phase II of the Clean Air Act without blending with other coals or using sulfur dioxide
reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for
low sulfur coal.
The following table presents the type of coal sales volumes by major coal region for the year ended December 31, 2019:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
Total Appalachia Basin
Illinois Basin
Northern Powder River Basin
Total
Type of Coal
Thermal
Metallurgical
Total
2,781
3,117
470
6,368
2,201
3,036
679
10,260
1,200
12,139
—
—
11,605
12,139
3,460
13,377
1,670
18,507
2,201
3,036
23,744
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Methodologies Used in Mineral Reserve Estimation
All of the reserves reported above are recoverable proven or probable reserves as determined in accordance with the SEC’s
Industry Guide 7 and are estimated by our internal geologists or independent third-party consultants. Significant internally generated
reserve studies are reviewed by independent third-party consultants. The technologies and economic data used in the estimation
of our proven or probable reserves include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach,
mine and coal quality, cross sections, statistical analysis and available public production data. There are numerous uncertainties
inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates
of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if
incorrect, result in an estimate that varies considerably from actual results. In addition, the SEC has adopted new rules to modernize
the property disclosure requirements for registrants with significant mining activities, which we will be required to begin to comply
with for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ending December
31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures. The new rules require that
reserve estimates that are reported be based on technical reports prepared using extensive mine-specific geological and engineering
data, as well as market and cost assumptions. As a royalty company, we may not have access to much of the information that is
required to prepare the technical reports used to determine reserves under the new rules without unreasonable burden or expense.
Accordingly, the amount of coal and other minerals that we are allowed to report under the new rules beginning with the year
ending December 31, 2021 may differ materially from the reserves reported above. See "Item 1A. Risk Factors—Risks Related
to Our Business—Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely
affect the quantities and value of our reserves. In addition, compliance with new SEC rules that will become effective beginning
in 2021 could result in material adjustments to the quantities of reserves we are allowed to report."
Major Coal Producing Properties
The following table provides a summary of our significant coal royalty properties by sales volumes for 2019 and is followed
by additional information for each property:
Region
Property/Lease Name
Operator(s)
Coal Type
2019 Sales Volumes
(Millions of Tons)
Appalachia Basin
Northern
Northern
Central
Central
Central
Central
Central
Southern
Illinois Basin
Illinois Basin
Illinois Basin
Northern Powder
River Basin
2.0
0.8
3.8
1.3
1.2
1.1
0.9
1.2
1.6
0.3
0.2
3.0
Hibbs Run
Mettiki Coal
Murray Energy Corporation
Thermal
Alliance Resource Partners
Met/Thermal
Contura-CAPP (VA)
Contura Energy, Inc.
Coal Mountain
CM Energy Properties, LP
Aracoma
Elk Creek
Lynch
Oak Grove
Macoupin
Williamson
Hillsboro
Contura Energy, Inc.
Ramaco Resources, Inc.
Blackjewel, LLC; InMet, LLC
Foresight Energy LP
Foresight Energy LP
Foresight Energy LP
Murray Metallurgical Coal Holdings LLC
Met
Met
Met
Met
Met
Met/Thermal
Thermal
Thermal
Thermal
Thermal
Western Energy
Rosebud Mining, LLC
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Appalachia Basin—Northern Appalachia
Hibbs Run. The Hibbs Run property is located in Marion County, West Virginia. In 2019, approximately 2.0 million tons
were sold from this thermal property. We lease this property to a subsidiary of Murray Energy Corporation. Coal from this property
is produced from longwall mines and shipped by rail to utility customers. The royalty rate for this property is a low fixed rate per
ton and has a significant effect on the weighted average per ton revenue for the region.
Mettiki Coal. The Mettiki Coal property is located in Tucker and Grant Counties, West Virginia. In 2019, approximately
0.8 million metallurgical and thermal tons were sold from this property. We lease this property to a subsidiary of Alliance Resource
Partners. Production comes from this mine via a longwall operation. Coal is shipped by truck to a local utility customer and by
train to metallurgical customers. NRP pays an override royalty equal to the royalty received from Mettiki to Western Pocahontas
Properties Limited Partnership per the terms of the deed.
The map below shows the location of our major properties in Northern Appalachia:
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Appalachia Basin—Central Appalachia
Contura-CAPP (VA). The Contura-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties,
Virginia. In 2019, approximately 3.8 million tons were sold from this property, substantially all of which was metallurgical coal.
We lease this property to subsidiaries of Contura Energy, Inc ("Contura Energy"). Production comes from underground room and
pillar and surface mines and is trucked to one of two preparation plants. Coal is shipped via the CSX and Norfolk Southern railroads
to utility and metallurgical customers.
Coal Mountain. The Coal Mountain property is located in Wyoming County, West Virginia. In 2019, approximately 1.3
million tons of metallurgical coal were sold from this property. We lease this property to CM Energy Properties, LP. Metallurgical
coal is produced from a multi-seam surface mine and coal is transported by truck to a preparation plant on the property. Coal is
shipped via the Norfolk Southern railroad to both domestic and export metallurgical customers.
Aracoma. The Aracoma property is located in Logan County, West Virginia. Approximately 1.2 million tons of coal,
substantially all of which is metallurgical coal, were sold in 2019 from this property. We lease this property to a subsidiary of
Contura Energy. Coal is produced from underground mines and transported by belt or truck to the preparation plant on the property.
Coal is shipped via the CSX railroad to export metallurgical customers.
Elk Creek. The Elk Creek property is located in Logan and Wyoming Counties, West Virginia. In 2019, approximately 1.1
million tons were sold from this property. We lease this property to Ramaco Resources, Inc. Metallurgical coal is produced from
surface and underground mines and is transported by belt and truck to a preparation plant on the property. Coal is shipped via the
CSX railroad to both domestic and export metallurgical customers.
Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky and Wise County, Virginia. In 2019,
approximately 0.9 million tons were sold from this property. Blackjewel, LLC ("Blackjewel") operated this property until it filed
for bankruptcy in the third quarter of 2019. InMet, LLC obtained lease rights to a substantial portion of this property through the
Blackjewel bankruptcy process and is currently operating on this lease. Production comes from underground room and pillar and
surface mines. This property has the ability to ship coal on the CSX and Norfolk Southern railroads to utility and metallurgical
customers.
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The map below shows the location of our major properties in Central Appalachia:
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Appalachia Basin—Southern Appalachia
Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2019, approximately 1.2 million tons of
metallurgical coal were sold from this property. We lease this property to Murray Metallurgical Coal Holdings, LLC ("Murray
Metallurgical"). The lease was transferred to Murray Metallurgical in connection with Mission Coal LLC's bankruptcy proceedings.
Production comes from a longwall mine and is transported by beltline to a preparation plant. Metallurgical products are then
shipped via railroad and barge to both domestic and export customers. While the mine was temporarily idled during the last quarter
of 2019 and Murray Metallurgical filed bankruptcy in the first quarter of 2020, the Oak Grove mine is expected to resume production
in 2020.
The map below shows the location of our major property in Southern Appalachia:
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Illinois Basin
Macoupin. The Macoupin property is located in Macoupin County, Illinois. This property is under lease to Macoupin
Energy, a subsidiary of Foresight Energy LP ("Foresight Energy"). In 2019, approximately 1.6 million tons of thermal coal were
sold from this property. Production is from an underground room and pillar mine. Coal is shipped by the Norfolk Southern or
Union Pacific railroads or by barge to domestic utility customers.
Williamson. The Williamson property is located in Franklin and Williamson Counties, Illinois. This property is under lease
to Williamson Energy, a subsidiary of Foresight Energy. In 2019, approximately 0.3 million tons of thermal coal were sold from
this property. Production comes from a longwall mine. Coal is shipped primarily via the Canadian National railroad to export
customers. In 2019, we also received overriding royalties from approximately 5.5 million tons of coal sold from non-NRP property.
Hillsboro. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. This property is under lease to
Hillsboro Energy, a subsidiary of Foresight Energy. This property had been idled from March 2015 until production resumed in
January 2019. In 2019, approximately 0.2 million tons of thermal coal were sold from this property. Production at the mine has
historically come from longwall mining methods; however, 2019 production came from continuous mining methods for
development of a longwall panel. Coal is shipped by rail via either the Union Pacific, Norfolk Southern or Canadian National
railroads, or by barges to domestic utilities customers.
In addition to these properties, we own loadout and other transportation assets at the Williamson and Macoupin mines and
at the Sugar Camp mine, which are also operated by Foresight Energy. See "—Coal Transportation and Processing Assets" below
for additional information on these assets.
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The map below shows the location of our major properties in the Illinois Basin:
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Northern Powder River Basin
Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2019,
approximately 3.0 million tons were sold from this property by a subsidiary of Rosebud Mining, LLC. Coal is produced by surface
dragline mining methods. Coal is transported by either truck or beltline to the Colstrip generation station located at the mine mouth.
The map below shows the location of our property in the Northern Powder River Basin:
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Coal Transportation and Processing Assets
We own transportation and processing infrastructure related to certain of our coal properties, including loadout and other
transportation assets at Foresight Energy's Williamson and Macoupin mines in the Illinois Basin, for which we collect throughput
fees or rents. We lease our Macoupin and Williamson transportation and processing infrastructure to subsidiaries of Foresight
Energy and are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we
subcontract to a subsidiary of Foresight Energy. In addition, we own rail loadout and associated infrastructure at the Sugar Camp
mine, an Illinois Basin mine also operated by a subsidiary of Foresight Energy. While we own coal reserves at the Williamson and
Macoupin mines, we do not own coal reserves at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a
subsidiary of Foresight Energy and we collect minimums and throughput fees. We recorded $19.3 million in revenue related to
our coal transportation and processing assets during the year ended December 31, 2019.
Other Coal Royalty and Other Segment Assets
As of December 31, 2019, we owned an estimated 172 million tons of aggregates reserves primarily located in Kentucky
and Indiana. We lease a portion of these reserves to third parties in exchange for royalty payments. The structure of these leases
is similar to our coal leases, and these leases typically require minimum rental payments in addition to royalties. In addition, we
hold overriding royalty interests in approximately 82 million tons of frac sand at operations in Wisconsin and Texas and sand and
gravel reserves in Washington. During 2019, our lessees sold 4.5 million tons from these properties and we received $4.3 million
in aggregates royalty revenues, including overriding royalty revenues.
Through our 51% ownership of BRP LLC ("BRP"), a joint venture with International Paper Company, we own approximately
10 million mineral acres in 31 states in the U.S. that include the following assets:
•
•
•
•
•
•
approximately 300,000 gross acres of oil and natural gas mineral rights primarily in Louisiana, of which over 53,000
acres were leased as of December 31, 2019;
approximately 50 million tons of aggregates reserves primarily located in North Carolina, Arkansas and South Carolina
and approximately 6 million tons of override royalty interest in South Carolina and Georgia;
approximately 2 million tons of coal reserves (primarily lignite and some bituminous coal) on 95,000 net mineral acres
of coal rights in the Gulf Coast region, of which approximately 5,600 acres are leased in Louisiana, Mississippi and
Texas;
an overriding royalty interest of 1% (net) on approximately 25,000 mineral acres in Louisiana;
copper rights in Michigan's Upper Peninsula; and
various other mineral rights including coalbed methane, metals, aggregates, water and geothermal, in several states
throughout the United States.
While the vast majority of the 10 million acres owned by BRP remain largely undeveloped, BRP has an ongoing program
to identify additional opportunities to lease its minerals to operating parties or otherwise monetize these assets.
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Soda Ash Segment
We own a 49% non-controlling equity interest in Ciner Wyoming. Ciner Resources LP, our operating partner, controls and
operates Ciner Wyoming. Ciner Resources LP mines the trona, processes it into soda ash, and distributes the soda ash both
domestically and internationally into the glass and chemicals industries. Ciner Resources LP is a publicly traded master limited
partnership that depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders.
Ciner Wyoming is one of the largest and lowest cost producers of soda ash in the world, serving a global market from its
facility located in the Green River Basin of Wyoming. The Green River Basin geological formation holds the largest, and one of
the highest purity, known deposits of trona ore in the world. Trona, a naturally occurring soft mineral, is also known as sodium
sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. Ciner Wyoming processes
trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other
consumer and industrial products. The vast majority of the world’s accessible trona reserves are located in the Green River Basin.
According to historical production statistics, approximately one-quarter of global soda ash is produced by processing trona, with
the remainder being produced synthetically through chemical processes. The costs associated with procuring the materials needed
for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-
based production consumes less energy and produces fewer undesirable by-products than synthetic production.
Ciner Wyoming’s Green River Basin surface operations are situated on approximately 880 acres in Wyoming, and its mining
operations consist of approximately 23,500 acres of leased and licensed subsurface mining area. The facility is accessible by both
road and rail. Ciner Wyoming uses seven large continuous mining machines and 14 underground shuttle cars in its mining operations.
Its processing assets consist of material sizing units, conveyors, calciners, dissolver circuits, thickener tanks, drum filters,
evaporators and rotary dryers.
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The following map provides an aerial overview of Ciner Wyoming’s surface operations:
In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering liquor, a solution
consisting of sodium carbonate dissolved in water. Ciner Wyoming then adds activated carbon to filters to remove organic impurities,
which can cause color contamination in the final product. The resulting clear liquid is then crystallized in evaporators, producing
sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge to remove excess water. The
resulting material is dried in a product dryer to form anhydrous sodium carbonate, or soda ash. The resulting processed soda ash
is then stored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. Ciner Wyoming’s
storage silos can hold up to 65,000 short tons of processed soda ash at any given time. The facility is in good working condition
and has been in service for 57 years.
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Deca Rehydration. The evaporation stage of trona ore processing produces a precipitate and natural by-product called deca.
"Deca," short for sodium carbonate decahydrate, is one part soda ash and ten parts water. Solar evaporation causes deca to crystallize
and precipitate to the bottom of the four main surface ponds at the Green River Basin facility. The deca rehydration process enables
Ciner Wyoming to recover soda ash from the deca-rich purged liquor as a by-product of the refining process. The soda ash contained
in deca is captured by allowing the deca crystals to evaporate in the sun and separating the dehydrated crystals from the soda ash.
The separated deca crystals are then blended with partially processed trona ore in the dissolving stage of the production process.
This process enables Ciner Wyoming to reduce waste storage needs and convert what is typically a waste product into a usable
raw material. Ciner Wyoming anticipates that its current deca stockpiles will be exhausted by 2023 and production rates decline
approximately 200,000 short tons per year if that production is not replaced.
Shipping and Logistics. All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the
year ended December 31, 2019, Ciner Wyoming shipped approximately 96.9% of its soda ash to its customers initially via a single
rail line owned and controlled by Union Pacific Railroad Company (“Union Pacific”). The Ciner Wyoming plant receives rail
service exclusively from Union Pacific. The agreement with Union Pacific expires on December 31, 2021 and there can be no
assurance that it will be renewed on terms favorable to Ciner Wyoming or at all. The rail freight rate charged under the agreement
increases annually based on a published index tied to certain rail industry metrics. Ciner Resources Corporation leases a fleet of
more than 2,000 hopper cars that serve as dedicated modes of shipment to its domestic customers. For export, Ciner Wyoming
ships soda ash on unit trains consisting of approximately 100 cars to two primary ports located in Texas and Oregon. From these
ports, the soda ash is loaded onto ships for delivery to ports all over the world. American Natural Soda Ash Corporation ("ANSAC")
currently provides logistics and support services for all of Ciner Wyoming’s export sales. For domestic sales, Ciner Resources
Corporation provides similar services.
Customers. Ciner Wyoming’s customers, including end users to whom ANSAC makes sales overseas, consist primarily of
glass manufacturing companies, which account for 50% or more of the consumption of soda ash around the world; and chemical
and detergent manufacturing companies. Ciner Wyoming’s largest customer currently is ANSAC, which buys soda ash (through
Ciner Resources Corporation, which serves as Ciner Wyoming’s sales agent in its agreement with ANSAC) and other of its member
companies for export to its customers. ANSAC accounted for approximately 60% of Ciner Wyoming’s net sales in 2019. ANSAC
takes soda ash orders directly from its overseas customers and then purchases soda ash for resale from its member companies pro
rata based on each member’s production volumes. ANSAC is the exclusive distributor for its members to the markets it serves.
However, Ciner Resources Corporation, on Ciner Wyoming’s behalf, negotiates directly with, and Ciner Wyoming exports to,
customers in markets not served by ANSAC.
In November 2018, Ciner Resources Corporation delivered a notice to terminate the membership in ANSAC, which will be
effective as of December 31, 2021. Until the effective termination date, ANSAC will continue to sell Ciner Wyoming’s soda ash
to ANSAC-designated overseas territories and continue to provide logistics and support services for Ciner Wyoming’s other export
sales. After the termination period, Ciner Resources Corporation will begin marketing soda ash directly into international markets
which are currently being served by ANSAC, and Ciner Wyoming intends to utilize the distribution network that has already been
established by the global Ciner Group. The ANSAC agreement provides that in the event an ANSAC member exits or the ANSAC
cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the
cooperative. The withdrawal from ANSAC is expected to enable Ciner Wyoming to combine volumes with Ciner Group’s soda
ash exports from Turkey and therefore to leverage the larger, global Ciner Group’s soda ash operations. Ciner Wyoming believes
this will eventually lower its cost position and improve its ability to optimize its market share both domestically and
internationally. However, initial costs may be higher than costs incurred through ANSAC sales. In addition, Ciner Wyoming will
need access to an international logistic infrastructure that includes, among other things, a domestic port for export capabilities.
These export capabilities are currently being developed by Ciner Group, and options being evaluated range from continued
outsourcing in the near term to developing Ciner Group’s own port capabilities in the longer term. Ciner Wyoming expects to bear
a portion of these development costs. See "Item 1A—Risk Factors—Risks Related to Our Business—A significant portion of
Ciner Wyoming’s historical international sales of soda ash have been to ANSAC, and the termination of the ANSAC membership
could adversely affect Ciner Wyoming’s ability to compete in certain international markets and increase Ciner Wyoming’s
international sales costs."
For customers in North America, Ciner Resources typically enters into contracts on Ciner Wyoming’s behalf with terms
ranging from one to three years. Under these contracts, customers generally agree to purchase either minimum estimated volumes
of soda ash or a certain percentage of their soda ash requirements at a fixed price for a given calendar year. Although Ciner Wyoming
does not have a “take or pay” arrangements with its customers, substantially all sales are made pursuant to written agreements and
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not through spot sales. In 2019, Ciner Wyoming had more than 70 domestic customers and has had long-term relationships with
the majority of its customers.
Leases and License. Ciner Wyoming is party to several mining leases and one license for its subsurface mining rights. Some
of the leases are renewable at Ciner Wyoming’s option upon expiration. Ciner Wyoming pays royalties to the State of Wyoming,
the U.S. Bureau of Land Management and Rock Springs Royalty Company, an affiliate of Occidental Petroleum Corporation
(formerly an affiliate of Anadarko Petroleum Corporation), which are calculated based upon a percentage of the value of soda ash
and related products sold at a certain stage in the mining process. These royalty payments may be subject to a minimum domestic
production volume from the Green River Basin facility. Ciner Wyoming is also obligated to pay annual rentals to its lessors and
licensor regardless of actual sales. In addition, Ciner Wyoming pays a production tax to Sweetwater County, and trona severance
tax to the State of Wyoming that is calculated based on a formula that utilizes the volume of trona ore mined and the value of the
soda ash produced.
Expansion Project. Ciner Wyoming has announced a significant capacity expansion capital project that would increase
production levels to up to 3.5 million tons of soda ash per year. Ciner Wyoming has conducted the initial basic design and is
currently evaluating and pursuing the related permits and detailed cost analysis pursuant to the basic design. This project will
require capital expenditures materially higher than have been incurred by Ciner Wyoming over the past few years, and Ciner
Wyoming intends to fund the project in part by reinvesting cash that would otherwise be distributed to its partners. In the third
quarter of 2019, Ciner Wyoming significantly reduced its cash distributions to its partners, and we expect for cash distributions
from Ciner Wyoming to remain at approximately $25 million to $28 million per year until the project is funded. However, the
costs of the expansion project could be higher than expected, or the execution of the project could be substantially delayed, which
could materially impact Ciner Wyoming’s profitability and result in a further reduction of cash distributions to us. See "Item 1A
—Risk Factors—Risks Related to Our Business—Significant delays and/or higher than expected costs associated with Ciner
Wyoming’s capacity expansion project could adversely affect Ciner Wyoming’s profitability and ability to make distributions to
us."
As a minority interest owner in Ciner Wyoming, we do not operate and are not involved in the day-to-day operation of the
trona ore mine or soda ash production plant. Our partner, Ciner Resources LP, manages the mining and plant operations. We appoint
three of the seven members of the Board of Managers of Ciner Wyoming and have certain limited negative controls relating to the
company.
Significant Customers
We have a significant concentration of revenues with Foresight Energy and its subsidiaries, with total revenues of $58.9
million in 2019 from four different mining operations, including transportation and processing services revenues, coal overriding
royalty revenues and wheelage revenues. We also have a significant concentration of revenues from Contura Energy, with total
revenues of $40.7 million in 2019 from several different mining operations, including wheelage revenues. For additional information
on significant customers, refer to "Item 8. Financial Statements and Supplementary Data—Note 15. Major Customers."
Competition
We face competition from land companies, coal producers, international steel companies and private equity firms in purchasing
coal reserves and royalty producing properties. Numerous producers in the coal industry make coal marketing intensely competitive.
Our lessees compete among themselves and with coal producers in various regions of the United States for domestic sales. Lessees
compete with both large and small producers nationwide on the basis of coal price at the mine, coal quality, transportation cost
from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain
are also affected by demand for electricity and steel, as well as government regulations, technological developments and the
availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, wind, solar and
hydroelectric power.
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Ciner Wyoming's trona mining and soda ash refinery business faces competition from a number of soda ash producers in the
United States, Europe and Asia, some of which have greater market share and greater financial, production and other resources
than Ciner Wyoming does. Some of Ciner Wyoming’s competitors are diversified global corporations that have many lines of
business and some have greater capital resources and may be in a better position to withstand a long-term deterioration in the soda
ash market. Other competitors, even if smaller in size, may have greater experience and stronger relationships in their local markets.
Competitive pressures could make it more difficult for Ciner Wyoming to retain its existing customers and attract new customers,
and could also intensify the negative impact of factors that decrease demand for soda ash in the markets it serves, such as adverse
economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly
increase the cost or limit the use of soda ash.
Title to Property
We owned substantially all of our coal and aggregates reserves in fee as of December 31, 2019. We lease the remainder from
unaffiliated third parties. Ciner Wyoming leases or licenses its trona reserves. We believe that we have satisfactory title to all of
our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is
subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection
with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe
that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially
interfere with their use in the operation of our business.
For most of our properties, the surface, oil and gas and mineral or coal estates are not owned by the same entities. Some of
those entities are our affiliates. State law and regulations in most of the states where we do business require the oil and gas owner
to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the
existence of the severed estates will materially impede development of the minerals on our properties.
Regulation and Environmental Matters
General
Operations on our properties must be conducted in compliance with all applicable federal, state and local laws and regulations.
These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety,
mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed,
management of materials generated by mining operations, surface subsidence from underground mining, water pollution,
legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife
protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable
laws and management of electrical equipment containing polychlorinated biphenyls ("PCBs"). Because of extensive,
comprehensive and often ambiguous regulatory requirements, violations during natural resource extraction operations are not
unusual and, notwithstanding compliance efforts, we do not believe violations can be eliminated entirely.
While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations,
those costs have been and are expected to continue to be significant. Our lessees in our coal and aggregates royalty businesses are
required to post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation
and mine closures, including the cost of treating mine water discharge when necessary. In many states our lessees also pay taxes
into reclamation funds that states use to achieve reclamation where site specific performance bonds are inadequate to do so.
Determinations by federal or state agencies that site specific bonds or state reclamation funds are inadequate could result in increased
bonding costs for our lessees or even a cessation of operations if adequate levels of bonding cannot be maintained. We do not
accrue for reclamation costs because our lessees are both contractually liable and liable under the permits they hold for all costs
relating to their mining operations, including the costs of reclamation and mine closures. Although the lessees typically accrue
adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals
to be insufficient. In recent years, compliance with these laws and regulations has substantially increased the cost of coal mining
for all domestic coal producers.
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In addition, the electric utility industry, which is the most significant end-user of thermal coal, is subject to extensive regulation
regarding the environmental impact of its power generation activities, which has affected and is expected to continue to affect
demand for coal mined from our properties. Current and future proposed legislation and regulations could be adopted that will
have a significant additional impact on the mining operations of our lessees or their customers’ ability to use coal and may require
our lessees or their customers to change operations significantly or incur additional substantial costs that would negatively impact
the coal industry.
Many of the statutes discussed below also apply to Ciner Wyoming’s trona mining and soda ash production operations, and
therefore we do not present a separate discussion of statutes related to those activities, except where appropriate.
Air Emissions
The Clean Air Act and corresponding state and local laws and regulations affect all aspects of our business. The Clean Air
Act directly impacts our lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases,
requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants.
The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric
power generating plants. There have been a series of federal rulemakings that are focused on emissions from coal-fired electric
generating facilities, including the Cross-State Air Pollution Rule ("CSAPR"), regulating emissions of nitrogen oxide and sulfur
dioxide, and the Mercury and Air Toxics Rule ("MATS"), regulating emissions of hazardous air pollutants. Installation of additional
emissions control technologies and other measures required under these and other U.S. Environmental Protection Agency ("EPA")
regulations make it more costly to operate coal-fired power plants and could make coal a less attractive or even effectively prohibited
fuel source in the planning, building and operation of power plants in the future. These rules and regulations have resulted in a
reduction in coal’s share of power generating capacity, which has negatively impacted our lessees’ ability to sell coal and our coal-
related revenues. Further reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed
rules and regulations would have a material adverse effect on our coal-related revenues.
Carbon Dioxide and Greenhouse Gas ("GHG") Emissions
In December 2009, EPA determined that emissions of carbon dioxide, methane, and other GHGs present an endangerment
to public health and welfare because emissions of such gases are, according to EPA, contributing to warming of the Earth’s
atmosphere and other climatic changes. Based on its findings, EPA began adopting and implementing regulations to restrict
emissions of GHGs under various provisions of the Clean Air Act.
In August 2015, EPA published its final Clean Power Plan ("CPP") Rule, a multi-factor plan designed to cut carbon pollution
from existing power plants, including coal-fired power plants. The rule required improving the heat rate of existing coal-fired
power plants and substituting lower carbon-emission sources like natural gas and renewables in place of coal. As promulgated,
the rule would force many existing coal-fired power plants to incur substantial costs in order to comply or alternatively result in
the closure of some of these plants, likely resulting in a material adverse effect on the demand for coal by electric power generators.
The rule was being challenged by several states, industry participants and other parties in the United States Court of Appeals for
the District of Columbia Circuit. In February 2016, the Supreme Court of the United States stayed the CPP Rule pending a decision
by the District of Columbia Circuit as well as any subsequent review by the Supreme Court. In April 2017, the United States Court
of Appeals for the District of Columbia Circuit granted EPA’s motion to hold the litigation in abeyance. In December 2017, EPA
issued a proposed rule repealing the CPP Rule and issued an Advance Notice of Proposed Rulemaking soliciting information
regarding a potential replacement rule to the CPP Rule. In August 2018, EPA formally proposed the Affordable Clean Energy
("ACE") Rule, which would replace the CPP Rule. The ACE Rule contemplates a narrower approach than the CPP Rule, focusing
on efficiency improvements at existing power plants and eliminating the CPP Rule’s broader goals that envisioned switches to
non-fossil fuel energy sources and the implementation of efficiency measures on demand-side entities, which the EPA now considers
beyond the reach of its authority under the Clean Air Act. The ACE Rule would also omit specific numerical emissions targets
that had been established under the CPP Rule. The ACE Rule went into effect on September 6, 2019. As a result, the United States
Court of Appeals for the District of Columbia Circuit dismissed the pending challenges to the CPP Rule as moot. The ACE Rule
has been challenged by public health groups, environmental groups, and a coalition of twenty-two states and six municipalities;
various industry groups and power providers have sought to intervene.
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In October 2015, EPA published its final rule on performance standards for greenhouse gas emissions from new, modified,
and reconstructed electric generating units. The final rule requires new steam generating units to use highly efficient supercritical
pulverized coal boilers that use partial post-combustion carbon capture and storage technology. The final emission standard is less
stringent than EPA had originally proposed due to updated cost assumptions, but could still have a material adverse effect on new
coal-fired power plants. The final rule has been challenged by several states, industry participants and other parties in the United
States Court of Appeals for the District of Columbia Circuit, but is not subject to a stay. In April 2017, the court granted EPA’s
motion to hold the litigation in abeyance while EPA reviews the rule.
President Obama also announced an emission reduction agreement with China’s President Xi Jinping in November 2014.
The United States pledged that by 2025 it would cut climate pollution by 26% to 28% from 2005 levels. China pledged it would
reach its peak carbon dioxide emissions around 2030 or earlier, and increase its non-fossil fuel share of energy to around 20% by
2030. In December 2015, the United States was one of 196 countries that participated in the Paris Climate Conference, at which
the participants agreed to limit their emissions in order to limit global warming to 2°C above pre-industrial levels, with an aspirational
goal of 1.5°C. While there is no way to estimate the impact of these climate pledges and agreements, they could ultimately have
an adverse effect on the demand for coal, both nationally and internationally, if implemented. In 2019, President Trump withdrew
from the Paris Climate Agreement.
Hazardous Materials and Waste
The Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or the Superfund law)
and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons
that are considered to have contributed to the release of a “hazardous substance” into the environment. We could become liable
under federal and state Superfund and waste management statutes if our lessees are unable to pay environmental cleanup costs
relating to hazardous substances. In addition, we may have liability for environmental clean-up costs in connection with Ciner
Wyoming's soda ash businesses.
Water Discharges
Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water Act and analogous
state laws and regulations create two permitting programs for mining operations. The National Pollutant Discharge Elimination
System (NPDES) program under Section 402 of the statute is administered by the states or EPA and regulates the concentrations
of pollutants in discharges of waste and storm water from a mine site. The Section 404 program is administered by the Army Corps
of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise “waters
of the United States.” The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and
may include land features not commonly understood to be a stream or wetlands. The Clean Water Act and its regulations prohibit
the unpermitted discharge of pollutants into such waters, including those from a spill or leak. Similarly, Section 404 also prohibits
discharges of fill material and certain other activities in waters unless authorized by the issued permit. In June 2015, EPA issued
a new rule defining the scope of “Waters of the United States” (WOTUS) that are subject to regulation. The 2015 WOTUS rule
was challenged by a number of states and private parties in federal district and circuit courts. In December 2017, EPA and the
Corps proposed a rule to repeal the 2015 WOTUS rule and implement the pre-2015 definition. The repeal of the 2015 WOTUS
rule took effect in December 2019. In December 2018, EPA and the Corps issued a proposed rule again revising the definition of
“Waters of the United States.” In January 2020, EPA and the Corps announced that the 2018 proposed rule was final. The repeal
of the 2015 WOTUS rule and implementation of the pre-2015 rule have been challenged in federal courts, and the 2020 final
WOTUS rule will likely be challenged as well.
In connection with its review of permits, EPA has at times sought to reduce the size of fills and to impose limits on specific
conductance (conductivity) and sulfate at levels that can be unachievable absent treatment at many mines. Such actions by EPA
could make it more difficult or expensive to obtain or comply with such permits, which could, in turn, have an adverse effect on
our coal-related revenues.
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In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators
and landowners. Since 2012, several citizen group lawsuits have been filed against mine operators for allegedly violating conditions
in their National Pollutant Discharge Elimination System (“NPDES”) permits requiring compliance with West Virginia’s water
quality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereas others alleged that
discharges of conductivity and sulfate were causing violations of West Virginia’s narrative water quality standards, which generally
prohibit adverse effects to aquatic life. The citizen suit groups have sought penalties as well as injunctive relief that would limit
future discharges of selenium, conductivity or sulfate. The federal district court for the Southern District of West Virginia has ruled
in favor of the citizen suit groups in multiple suits alleging violations of the water quality standard for selenium and in two suits
alleging violations of water quality standards due to discharges of conductivity (one of which was upheld on appeal by the United
States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges
of selenium, conductivity or sulfate could result in large treatment expenses for our lessees. In 2015, the West Virginia Legislature
enacted certain changes to West Virginia’s NPDES program to expressly prohibit the direct enforcement of water quality standards
against permit holders. EPA approved those changes as a program revision effective March 27, 2019. This approval may prevent
future citizen suits alleging violations of water quality standards.
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 has been closed, the property has been reclaimed, and the state reclamation bond has
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.
Other Regulations Affecting the Mining Industry
Mine Health and Safety Laws
The operations of our coal lessees and Ciner Wyoming are subject to stringent health and safety standards that have been
imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of
1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly
expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive
health and safety standards on all mining operations. In addition, the Black Lung Acts require payments of benefits by all businesses
conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who
have died from this disease.
Mining accidents in recent years have received national attention and instigated responses at the state and national level that
have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground
mining operations. Since 2006, heightened scrutiny has been applied to the safe operations of both underground and surface mines.
This increased level of review has resulted in an increase in the civil penalties that mine operators have been assessed for non-
compliance. Operating companies and their supervisory employees have also been subject to criminal convictions. The Mine Safety
and Health Administration ("MSHA") has also advised mine operators that it will be more aggressive in placing mines in the
Pattern of Violations program, if a mine’s rate of injuries or significant and substantial citations exceed a certain threshold. A mine
that is placed in a Pattern of Violations program will receive additional scrutiny from MSHA.
Surface Mining Control and Reclamation Act of 1977
The Surface Mining Control and Reclamation Act of 1977 ("SMCRA") and similar statutes enacted and enforced by the
states impose on mine operators the responsibility of reclaiming the land and compensating the landowner for types of damages
occurring as a result of mining operations. To ensure compliance with any reclamation obligations, mine operators are required
to post performance bonds. Our coal lessees are contractually obligated under the terms of our leases to comply with all federal,
state and local laws, including SMCRA. Upon completion of the mining, reclamation generally is completed by seeding with
grasses or planting trees for use as pasture or timberland, as specified in the reclamation plan approved by the state regulatory
authority. In addition, higher and better uses of the reclaimed property are encouraged.
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Mining Permits and Approvals
Numerous governmental permits or approvals such as those required by SMCRA and the Clean Water Act are required for
mining operations. In connection with obtaining these permits and approvals, our lessees may be required to prepare and present
to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the
environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay
commencement or continuation of mining operations.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must
submit a reclamation plan for reclaiming the mined property upon the completion of mining operations. Our lessees have obtained
or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. Our lessees
are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years.
However, given the imposition of new requirements in the permits in the form of policies and the increased oversight review that
has been exercised by EPA, there are no assurances that they will not experience difficulty and delays in obtaining mining permits
in the future. In addition, EPA has used its authority to create significant delays in the issuance of new permits and the modification
of existing permits, which has led to substantial delays and increased costs for coal operators.
Employees and Labor Relations
As of December 31, 2019, affiliates of our general partner employed 56 people who directly supported our operations. None
of these employees were subject to a collective bargaining agreement.
Website Access to Partnership Reports
Our Internet address is www.nrplp.com. We make available free of charge on or through our Internet website our Annual
Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not
a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information
statements and other information filed by us.
Corporate Governance Matters
Our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy and our Corporate Governance
Guidelines adopted by our Board of Directors, as well as the charter for our Audit Committee are available on our website at
www.nrplp.com. Copies of our annual report, our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures
Policy, our Corporate Governance Guidelines and our committee charters will be made available upon written request to our
principal executive office at 1201 Louisiana St., Suite 3400, Houston, Texas 77002.
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ITEM 1A.
RISK FACTORS
Risks Related to Our Business
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In
addition, our debt agreements and our partnership agreement place restrictions on our ability to pay, and in some cases raise,
the quarterly distribution under certain circumstances.
Because distributions on the common units are dependent on the amount of cash we generate, distributions fluctuate based
on our performance. The actual amount of cash that is available to be distributed each quarter depends on numerous factors, some
of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow,
and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods
when we record losses and might not be made during periods when we record profits. The actual amount of cash we have to
distribute each quarter is reduced by payments in respect of debt service and other contractual obligations, including distributions
on the preferred units, fixed charges, maintenance capital expenditures and reserves for future operating or capital needs that the
board of directors may determine are appropriate. We have significant debt service obligations and obligations to pay cash
distributions on our preferred units. To the extent our board of directors deems appropriate, it may determine to decrease the amount
of the quarterly distribution on our common units or suspend or eliminate the distribution on our common units altogether. In
addition, because our unitholders are required to pay income taxes on their respective shares of our taxable income, our unitholders
may be required to pay taxes in excess of any future distributions we make. Our unitholders' share of our portfolio income may
be taxable to them even though they receive other losses from our activities. See "—Tax Risks to Our Unitholders—Our unitholders
are required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Our unitholders'
share of our portfolio income may be taxable to them even though they receive other losses from our activities."
The agreements governing our indebtedness and preferred units restrict our ability to raise, and in some cases continue to
pay, distributions on our common units. Opco’s revolving credit agreement, the indenture governing our 2025 Senior Notes and
our partnership agreement each require that we meet certain consolidated leverage tests in order to raise our quarterly distribution
on the common units above the current level of $0.45 per quarter. The maximum leverage covenant under Opco’s revolving credit
facility will step down permanently from 4.0x to 3.0x if we increase the common unit distribution above the current level of $0.45
per common unit per quarter. In addition, under our partnership agreement, to the extent we have paid any distributions on the
preferred units in kind ("PIK units") and such PIK units are still outstanding at any time after January 1, 2022, we will be prohibited
from making any distributions with respect to our common units until we have redeemed all such PIK units in cash. For more
information on restrictions on our ability to make distributions on our common units, see "Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and "Item 8. Financial Statements
and Supplementary Data—Note 12. Debt, Net."
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business
prospects.
As of December 31, 2019, we and our subsidiaries had approximately $524.1 million of total indebtedness. The terms and
conditions governing the indenture for NRP’s 2025 Senior Notes and Opco’s revolving credit facility and senior notes:
•
•
•
•
•
require us to meet certain leverage and interest coverage ratios;
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing
the cash available to finance our operations and other business activities and could limit our flexibility in planning for
or reacting to changes in our business and the industries in which we operate;
increase our vulnerability to economic downturns and adverse developments in our business;
limit our ability to access the bank and capital markets to raise capital on favorable terms or to obtain additional financing
for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage
in business combinations;
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•
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall
size or less restrictive terms governing their indebtedness;
• make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may
default on our debt obligations; and
•
limit management’s discretion in operating our business.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by
financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic
conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal
and interest on our debt and meet our other obligations, including payment of distributions on the preferred units. If we do not
have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money, or sell assets or raise
equity at unattractive prices, including higher interest rates. We are required to make substantial principal repayments each year
in connection with Opco’s senior notes, with approximately $46 million due thereunder during 2020. To the extent we borrow to
make some of these payments, we may not be able to refinance these amounts on terms acceptable to us, if at all. We may not be
able to refinance our debt, sell assets, borrow more money or access the bank and capital markets on terms acceptable to us, if at
all. Our ability to comply with the financial and other restrictive covenants in our debt agreements will be affected by the levels
of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants
would result in an event of default under our indebtedness, and such an event of default could adversely affect our business,
financial condition and results of operations.
In July 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to
submit LIBOR rates after 2021. Opco’s revolving credit facility includes provisions to determine a replacement rate for LIBOR
if necessary during its term, which provide that we will adopt a replacement rate that is broadly accepted by the syndicated loan
market. We currently do not expect the transition from LIBOR to have a material impact on us. However, if clear market standards
and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty establishing
a replacement rate under Opco’s revolving credit facility. In the event that we do not determine a replacement rate for LIBOR, in
certain circumstances, Eurodollar Loans under Opco’s revolving credit facility may be suspended and converted to ABR Loans,
which could bear higher interest rates. If we are unable to negotiate replacement rates on favorable terms, it could adversely affect
our business, financial condition and results of operations. For a description of the interest rate on borrowings under Opco’s
revolving credit facility, see “Item 8. Financial Statements and Supplementary Data—Note 12. Debt, Net.”
Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines
in prices could have a material adverse effect on our business and results of operations.
Coal prices continue to be volatile and prices could decline substantially from current levels. Production by some of our
lessees may not be economic if prices decline further or remain at current levels. The prices our lessees receive for their coal
depend upon factors beyond their or our control, including:
•
•
•
•
•
•
•
•
•
the supply of and demand for domestic and foreign coal;
domestic and foreign governmental regulations and taxes;
changes in fuel consumption patterns of electric power generators;
the price and availability of alternative fuels, especially natural gas;
global economic conditions, including the strength of the U.S. dollar relative to other currencies;
global and domestic demand for steel;
tariff rates on imports and trade disputes, particularly involving the United States and China;
the availability of, proximity to and capacity of transportation networks and facilities;
global or national health concerns, including the outbreak of pandemic or contagious disease, such as the recent
coronavirus;
• weather conditions; and
•
the effect of worldwide energy conservation measures.
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Natural gas is the primary fuel that competes with thermal coal for power generation, and renewable energy sources continue
to gain market share in power generation. The abundance and ready availability of cheap natural gas, together with increased
governmental regulations on the power generation industry has caused a number of utilities to switch from thermal coal to natural
gas and/or close coal-powered generation plants. This switching has resulted in a decline in thermal coal prices, and to the extent
that natural gas prices remain low, thermal coal prices will also remain low. Reduced international demand for export thermal coal
and increased competition from global producers has also put downward pressure on thermal coal prices.
Our lessees produce a significant amount of metallurgical coal that is used for steel production domestically and internationally.
Since the amount of steel that is produced is tied to global economic conditions, declines in those conditions could result in the
decline of steel, coke and metallurgical coal production. Since metallurgical coal is priced higher than thermal coal, some mines
on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If these mines are
unable to sell metallurgical coal, they may not be economically viable and may be temporarily idled or closed. Any potential future
lessee bankruptcy filings could create additional uncertainty as to the future of operations on our properties and could have a
material adverse effect on our business and results of operations.
To the extent our lessees are unable to economically produce coal over the long term, the carrying value of our reserves could
be adversely affected. A long-term asset generally is deemed impaired when the future expected cash flow from its use and
disposition is less than its book value. For the fourth quarter of 2019, we recorded an impairment charge of approximately $148
million related to properties that we believe our current or future lessees are unable to operate profitably. Future impairment
analyses could result in additional downward adjustments to the carrying value of our assets.
We derive a large percentage of our revenues and other income from a small number of coal lessees.
Challenges in the coal mining industry have led to significant consolidation activity. We own significant interests in all four
of Foresight Energy’s mining operations, which accounted for approximately 23% of our total revenues in 2019. We also own
significant interests in several of Contura Energy's mining operations, which accounted for approximately 16% of our total revenues
in 2019. Certain other lessees have made acquisitions over the past few years resulting in their having an increased interest in our
coal reserves. Any interruption in these lessees’ ability to make royalty payments to us could have a disproportionate material
adverse effect on our business and results of operations.
Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect
on our business and results of operations.
The current coal price environment, together with high operating costs and limited access to capital, has caused a number
of coal producers to file for protection under U.S. bankruptcy and/or idle or close mines that they cannot operate profitably. To
the extent our leases are accepted or assigned in a bankruptcy process, pre-petition amounts are required to be cured in full, but
we may ultimately make concessions in the financial terms of those leases in order for the reorganized company or new lessor to
operate profitably going forward. To the extent our leases are rejected, operations on those leases will cease, and we will be unlikely
to recover the full amount of our rejection damages claims. More of our lessees may file for bankruptcy in the future, which will
create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our business
and results of operations. Foresight Energy, which is our largest lessee, is currently working with its lenders and contract
counterparties to evaluate restructuring options, which could result in the idling or closure of one or more of its mines or changes
in lease terms. To the extent Foresight determines to idle operations on our properties for a prolonged period or to shut any of its
mines on our properties down permanently, or to the extent we agree to amend the terms of our leases with them to facilitate their
continued operations on our properties, our business and results of operations could be adversely affected.
Mining operations are subject to operating risks that could result in lower revenues to us.
Our revenues are largely dependent on the level of production of minerals from our properties, and any interruptions to or
increases in costs of the production from our properties may reduce our revenues. The level of production and costs thereof are
subject to operating conditions or events beyond our or our lessees’ control including:
•
•
•
difficulties or delays in acquiring necessary permits or mining or surface rights;
reclamation costs and bonding costs;
changes or variations in geologic conditions, such as the thickness of the mineral deposits and the amount of rock
embedded in or overlying the mineral deposit;
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• mining and processing equipment failures and unexpected maintenance problems;
•
•
•
•
the availability of equipment or parts and increased costs related thereto;
the availability of transportation networks and facilities and interruptions due to transportation delays;
adverse weather and natural disasters, such as heavy rains and flooding;
labor-related interruptions and trained personnel shortages; and
• mine safety incidents or accidents, including hazardous conditions, roof falls, fires and explosions.
While our lessees maintain insurance coverage, there is no assurance that insurance will be available or cover the costs of
these risks. Many of our lessees are experiencing rising costs related to regulatory compliance, insurance coverage, permitting and
bonding, transportation, and labor. Increased costs result in decreased profitability for our lessees and reduce the competitiveness
of coal as a fuel source. In addition, we and our lessees may also incur costs and liabilities resulting from third-party claims for
damages to property or injury to persons arising from their operations. The occurrence of any of these events or conditions could
have a material adverse effect on our business and results of operations.
The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air
pollutants have resulted in changes in fuel consumption patterns by electric power generators and a corresponding decrease
in coal production by our lessees and reduced coal-related revenues.
Enactment of laws and passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states
or other countries, or other actions to limit such emissions, have resulted in and could continue to result in electricity generators
switching from coal to other fuel sources and in coal-fueled power plant closures. Further, regulations regarding new coal-fueled
power plants could adversely impact the global demand for coal. The potential financial impact on us of existing and future laws,
regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to
diminish their reliance on coal as a fuel source. The amount of coal consumed for domestic electric power generation is affected
primarily by the overall demand for electricity, the price and availability of competing fuels for power plants and environmental
and other governmental regulations. We expect that substantially all newly constructed power plants in the United States will be
fired by natural gas because of lower construction and compliance costs compared to coal-fired plants and because natural gas is
a cleaner burning fuel. The increasingly stringent requirements of rules and regulations promulgated under the federal Clean Air
Act have resulted in more electric power generators shifting from coal to natural-gas-fired power plants, or to other alternative
energy sources such as solar and wind. These changes have resulted in reduced coal consumption and the production of coal from
our properties and are expected to continue to have an adverse effect on our coal-related revenues.
In addition to EPA’s greenhouse gas initiatives, there are several other federal rulemakings that are focused on emissions
from coal-fired electric generating facilities, including the Cross-State Air Pollution Rule (CSAPR), regulating emissions of nitrogen
oxide and sulfur dioxide, and the Mercury and Air Toxics Rule (MATS), regulating emissions of hazardous air pollutants. Installation
of additional emissions control technologies and other measures required under these and other EPA regulations have made it more
costly to operate many coal-fired power plants and have resulted in and are expected to continue to result in plant closures. Further
reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed rules and regulations
would have a material adverse effect on our coal-related revenues. For more information on regulation of greenhouse gas and other
air pollutant emissions, see "Items 1. and 2. Business and Properties—Regulation and Environmental Matters.”
Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also
resulting in unfavorable lending and investment policies by institutions and insurance companies which could significantly
affect our ability to raise capital or maintain current insurance levels.
Global climate issues continue to attract public and scientific attention. Numerous reports have engendered concern about the
impacts of human activity, especially fossil fuel combustion, on global climate issues. In addition to government regulation of
greenhouse gas and other air pollutant emissions, there have also been efforts in recent years affecting the investment community,
including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the
divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels,
such as coal. The impact of such efforts may adversely affect our ability to raise capital. In addition, a number of insurance
companies have taken action to limit coverage for companies in the coal industry, which could result in significant increases in
our costs of insurance or in our inability to maintain insurance coverage at current levels.
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In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state
and local laws and regulations that may limit production from our properties and our profitability.
The operations of our lessees and Ciner Wyoming are subject to stringent health and safety standards under increasingly
strict federal, state and local environmental, health and safety laws, including mine safety regulations and governmental enforcement
policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal
penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations,
the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from
our properties.
New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations
governing permitting requirements, could further regulate or tax mining industries and may also require significant changes to
operations, the incurrence of increased costs or the requirement to obtain new or different permits, any of which could decrease
our revenues and have a material adverse effect on our financial condition or results of operations. Under SMCRA, our coal lessees
have substantial reclamation obligations on properties where mining operations have been completed and are required to post
performance bonds for their reclamation obligations. To the extent an operator is unable to satisfy its reclamation obligations or
the performance bonds posted are not sufficient to cover those obligations, regulatory authorities or citizens groups could attempt
to shift reclamation liability onto the ultimate landowner, which if successful, could have a material adverse effect on our financial
condition.
In addition to governmental regulation, private citizens’ groups have continued to be active in bringing lawsuits against coal
mine operators and land owners that allege violations of water quality standards resulting from ongoing discharges of pollutants
from reclaimed mining operations, including selenium and conductivity. Any determination that a landowner or lessee has liability
for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and
reclaimed coal mine operations and could result in substantial compliance costs or fines.
Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on our
results of operations.
The market price of soda ash directly affects the profitability of Ciner Wyoming’s soda ash production 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. The prices Ciner
Wyoming receives for its soda ash depend on numerous factors beyond Ciner Wyoming’s control, including worldwide and regional
economic and political conditions impacting supply and demand. Glass manufacturers and other industrial customers drive most
of the demand for soda ash, and these customers experience significant fluctuations in demand and production costs. Competition
from increased use of glass substitutes, such as plastic and recycled glass, has had a negative effect on demand for soda ash.
Substantial or extended declines in prices for soda ash could have a material adverse effect on our results of operations. In addition,
Ciner Wyoming relies on natural gas as the main energy source in its soda ash production process. Accordingly, high natural gas
prices increase Ciner Wyoming’s cost of production and affect its competitive cost position when compared to other foreign and
domestic soda ash producers.
If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.
We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business
decisions with respect to their operations within the constraints of their leases, including decisions relating to:
•
the payment of minimum royalties;
• marketing of the minerals mined;
• mine plans, including the amount to be mined and the method and timing of mining activities;
•
•
•
•
processing and blending minerals;
expansion plans and capital expenditures;
credit risk of their customers;
permitting;
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•
•
•
•
•
insurance and surety bonding;
acquisition of surface rights and other mineral estates;
employee wages;
transportation arrangements;
compliance with applicable laws, including environmental laws; and
• mine closure and reclamation.
A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us
the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of
our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might
not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could
be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease
to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell
minerals at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for
small or isolated mineral reserves.
We are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture and
through our ownership of certain coal transportation assets.
We do not have control over the operations of Ciner Wyoming. We have limited approval rights with respect to Ciner Wyoming,
and our partner controls most business decisions, including decisions with respect to distributions and capital expenditures. Adverse
developments in Ciner Wyoming’s business, including increased maintenance and expansion capital expenditures that we may be
required to fund, would result in decreased distributions to NRP. In addition, we are ultimately responsible for operating the
transportation infrastructure at Foresight Energy’s Williamson mine, and have assumed the capital and operating risks associated
with that business. As a result of these investments, we could experience increased costs as well as increased liability exposure
associated with operating these facilities.
A significant portion of Ciner Wyoming’s historical international sales of soda ash have been to ANSAC, and the termination
of the ANSAC membership could adversely affect Ciner Wyoming’s ability to compete in certain international markets and
increase Ciner Wyoming’s international sales costs.
ANSAC has historically been Ciner Wyoming’s largest customer for the years ended December 31, 2019, 2018 and 2017,
accounting for 60%, 52% and 45%, respectively, of its net sales. Following termination of the membership in ANSAC, which will
be effective December 31, 2021, there is no assurance that Ciner Wyoming will be able to retain existing foreign customers or
secure new foreign customers or the related logistics arrangements on favorable terms. The costs to transport and market soda ash
following the ANSAC exit could be higher than costs associated with sales through ANSAC. In addition, Ciner Wyoming will
need access to an international logistic infrastructure that includes, among other things, a domestic port for export capabilities.
These export capabilities are currently being developed by Ciner Group, and options being evaluated range from continued
outsourcing in the near term to developing Ciner Group’s own port capabilities in the longer term. There can be no assurance that
sufficient export capacity will be obtained. In addition, the costs associated with a domestic export terminal could be higher than
expected. Adverse developments in Ciner Wyoming’s ability to export soda ash and sell into the foreign markets currently served
by ANSAC could result in lower cash distributions to us from Ciner Wyoming.
Significant delays and/or higher than expected costs associated with Ciner Wyoming’s capacity expansion project could
adversely affect Ciner Wyoming’s profitability and ability to make distributions to us.
Ciner Wyoming has announced a significant capacity expansion capital project intended to increase production levels to up
to 3.5 million tons of soda ash per year. This project will require capital expenditures materially higher than have been incurred
by Ciner Wyoming over the past few years, and Ciner Wyoming intends to fund the project in part by reinvesting cash that would
otherwise be distributed to its partners. In the third quarter of 2019, Ciner Wyoming significantly reduced its cash distributions to
its partners, and we expect cash distributions to remain at the current lower level until the project is funded. However, the costs
of the expansion project could be higher than expected, or the execution of the project could be substantially delayed, which could
materially impact Ciner Wyoming’s profitability and result in a further reduction of cash distributions to us. In addition, Ciner
Wyoming's deca stockpiles will be substantially depleted by 2023. Without adding capacity through the expansion project, Ciner
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Wyoming's production rates would decline approximately 200,000 short tons, which would further impact Ciner Wyoming's
profitability.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal,
soda ash and other minerals from our properties.
Transportation costs represent a significant portion of the total delivered cost for the customers of our lessees. Increases in
transportation costs could make coal a less competitive source of energy or could make minerals produced by some or all of our
lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs
could result in increased competition for our lessees from producers in other parts of the country.
Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals to their customers. Disruption of those
transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and/or other events
could temporarily impair the ability of our lessees to supply coal to their customers and/or increase their costs. Many of our lessees
are currently experiencing transportation-related issues due in particular to decreased availability and reliability of rail services
and port congestion. Our lessees’ transportation providers may face difficulties in the future that would impair the ability of our
lessees to supply minerals to their customers, resulting in decreased royalty revenues to us.
In addition, Ciner Wyoming transports its soda ash by rail or truck and ocean vessel. As a result, its business and financial
results are sensitive to increases in rail freight, trucking and ocean vessel rates. Increases in transportation costs, including increases
resulting from emission control requirements, port taxes and fluctuations in the price of fuel, could make soda ash a less competitive
product for glass manufacturers when compared to glass substitutes or recycled glass, or could make Ciner Wyoming’s soda ash
less competitive than soda ash produced by competitors that have other means of transportation or are located closer to their
customers. Ciner Wyoming may be unable to pass on its freight and other transportation costs in full because market prices for
soda ash are generally determined by supply and demand forces. In addition, rail operations are subject to various risks that may
result in a delay or lack of service at Ciner Wyoming’s facility, and alternative methods of transportation are impracticable or cost
prohibitive. For the year ended December 31, 2019, Ciner Wyoming shipped approximately 96.9% of its soda ash from the Green
River facility on a single rail line owned and controlled by Union Pacific. Ciner Wyoming’s current transportation contract with
Union Pacific expires on December 31, 2021. There can be no assurance that this contract will be renewed on terms favorable to
Ciner Wyoming or at all. Any substantial interruption in or increased costs related to the transportation of Ciner Wyoming’s soda
ash or the failure to renew the rail contract on favorable terms could have a material adverse effect on our financial condition and
results of operations.
Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities
and value of our reserves. In addition, compliance with new SEC rules that will become effective beginning in 2021 could result
in material adjustments to the quantities of reserves we are allowed to report.
Coal, aggregates and industrial minerals reserve engineering requires subjective estimates of underground accumulations of
coal, aggregates and industrial minerals, and assumptions and are by nature imprecise. Our reserve estimates may vary substantially
from the actual amounts of coal, aggregates and industrial minerals recovered from our reserves. There are numerous uncertainties
inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of reserves necessarily depend
upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably
from actual results. These factors and assumptions relate to:
•
•
•
•
•
future prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs;
production levels;
future technology improvements;
the effects of regulation by governmental agencies; and
geologic and mining conditions, which may not be fully identified by available exploration data.
Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations
may be material. As a result, undue reliance should not be placed on our reserve data that is included in this report.
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In addition, the SEC has adopted new rules to modernize the property disclosure requirements for registrants with significant
mining activities, which we will be required to begin to comply with for the fiscal year beginning on January 1, 2021 (reported in
the Annual Report on Form 10-K for the year ending December 31, 2021). We are in the process of assessing the impact the new
rules will have on our disclosures. The new rules require that reserve estimates that are reported be based on technical reports
prepared using extensive mine-specific geological and engineering data, as well as market and cost assumptions. As a royalty
company, we lease coal reserves to third-party operators that have sole control of the mining and selling of coal from our properties.
We may not have access to much of the information that is required to prepare the technical reports used to determine reserves
under the new rules without unreasonable burden or expense. Accordingly, the amount of coal and other minerals that we are
allowed to report under the new rules beginning with the year ending December 31, 2021 may differ materially from what we are
currently reporting.
Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability
to receive amounts in excess of minimum royalty payments.
Mineral supply contracts generally do not require operators to satisfy their obligations to their customers with resources
mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with minerals mined from
properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mine operating
costs, cost and availability of transportation, and customer specifications. In addition, lessees move on and off of our properties
over the course of any given year in accordance with their mine plans. If a lessee satisfies its obligations to its customers with
minerals from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty
revenues.
A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection
process or, if identified, might be identified in a subsequent period.
We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits
and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them
in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and
errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.
Our business is subject to cybersecurity risks.
Our business is increasingly dependent on information technologies and services. Threats to information technology systems
associated with cybersecurity risks and cyber incidents or attacks continue to grow. Although we utilize various procedures and
controls to mitigate our exposure to such risks, cybersecurity attacks and other cyber events are evolving, unpredictable, and
sometimes difficult to detect, and could lead to unauthorized access to sensitive information or render data or systems unusable.
We do not presently maintain insurance coverage to protect against cybersecurity risks. If we procure such coverage in the
future, we cannot ensure that it will be sufficient to cover any particular losses we may experience as a result of such cyber attacks.
Any cyber incident could have a material adverse effect on our business, financial condition and results of operations.
Risks Related to Our Structure
Unitholders may not be able to remove our general partner even if they wish to do so.
Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only
limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of
the general partner on an annual or any other basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical
ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon
the vote of the holders of at least 66 2/3% of our outstanding common units (including common units held by our general partner
and its affiliates and including common units deemed to be held by the holders of the preferred units who vote along with the
common unitholders on an as-converted basis). Because of their substantial ownership in us, the removal of our general partner
would be difficult without the consent of both our general partner and its affiliates and the holders of the preferred units.
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In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to
remove our general partner or otherwise change our management:
•
•
generally, if a person (other than the holders of preferred units) acquires 20% or more of any class of units then outstanding
other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and
our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information
about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of
management.
As a result of these provisions, the price at which the common units will trade may be lower because of the absence or
reduction of a takeover premium in the trading price.
The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of
additional common units in the future, which could result in substantial dilution of our common unitholders’ ownership
interests.
The preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. We are
required to pay quarterly distributions on the preferred units (plus any PIK units issued in lieu of preferred units) in an amount
equal to 12.0% per year prior to paying any distributions on our common units. The preferred units also rank senior to the common
units in right of liquidation and will be entitled to receive a liquidation preference in any such case.
The preferred units may also be converted into common units under certain circumstances. The number of common units
issued in any conversion will be based on the then-current trading price of the common units at the time of conversion. Accordingly,
the lower the trading price of our common units at the time of conversion, the greater the number of common units that will be
issued upon conversion of the preferred units, which would result in greater dilution to our existing common unitholders. Dilution
has the following effects on our common unitholders:
•
•
•
an existing unitholder’s proportionate ownership interest in NRP will decrease;
the amount of cash available for distribution on each unit may decrease; and
the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common
units may decline.
In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the
preferred will have the right to remove our general partner.
We may issue additional common units or preferred units without common unitholder approval, which would dilute a
unitholder’s existing ownership interests.
Our general partner may cause us to issue an unlimited number of common units, without common unitholder approval
(subject to applicable New York Stock Exchange (NYSE) rules). We may also issue at any time an unlimited number of equity
securities ranking junior or senior to the common units (including additional preferred units) without common unitholder approval
(subject to applicable NYSE rules). In addition, we may issue additional common units upon the exercise of the outstanding
warrants held by Blackstone and Goldentree. The issuance of additional common units or other equity securities of equal or senior
rank will have the following effects:
•
•
•
an existing unitholder’s proportionate ownership interest in NRP will decrease;
the amount of cash available for distribution on each unit may decrease; and
the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common
units may decline.
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Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the
right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common
units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result,
unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less
than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.
Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to
unitholders.
Prior to making any distribution on the common units, we reimburse our general partner and its affiliates, including officers
and directors of the general partner, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of
fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of
these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable
fees as determined by the general partner.
Conflicts of interest could arise among our general partner and us or the unitholders.
These conflicts may include the following:
• We do not have any employees and we rely solely on employees of affiliates of the general partner;
•
•
•
•
•
under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the
partnership;
the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly
distributions to unitholders;
the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its
assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach
its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without
limiting the general partner’s liability;
under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and
reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us.
Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arm’s-length
negotiations; and
the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership
interests or by assigning its call rights to one of its affiliates or to us.
In addition, Blackstone has certain consent rights and board appointment and observation rights. GoldenTree also has more
limited consent rights. In the exercise of their applicable consent rights and/or board rights, conflicts of interest could arise between
us and our general partner on the one hand, and Blackstone or GoldenTree on the other hand.
The control of our general partner may be transferred to a third party without unitholder consent. A change of control may
result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation
arrangements.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all
of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability
of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party.
The new owner of our general partner would then be in a position to replace the Board of Directors and officers with its own
choices and to control their decisions and actions.
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In addition, a change of control would constitute an event of default under our debt agreements. During the continuance of
an event of default under our debt agreements, the administrative agent may terminate any outstanding commitments of the lenders
to extend credit to us and/or declare all amounts payable by us immediately due and payable. In addition, upon a change of control,
the holders of the preferred units would have the right to require us to redeem the preferred units at the liquidation preference or
convert all of their preferred units into common units. A change of control also may trigger payment obligations under various
compensation arrangements with our officers.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities,
except for those contractual obligations that are expressly made without recourse to our general partner. Under Delaware law,
however, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the
right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation
in the "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides
that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from
the date of the distribution.
Tax Risks to Our Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject
to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as
a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level
taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership
for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would
be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based on
our current operations and current Treasury regulations, we believe we satisfy the qualifying income requirement. However, we
have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the
qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income
tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate and would likely be liable for state income tax at varying rates. Distributions to our unitholders
would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through
to our unitholders. Because tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders
would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated
cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation. Imposition of a similar tax on us in a jurisdiction in which we
operate or in other jurisdictions to which we may expand could substantially reduce the cash available for distribution to our
unitholders.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial
or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units
may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time,
members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly
traded partnerships. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more
difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S.
federal income tax purposes. For example, the “Clean Energy for America Act,” which is similar to legislation that was commonly
proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among
other things, repeal the qualifying income exception within Section 7704(d)(1)(E) of the Code upon which we rely for our status
as a partnership for U.S. federal income tax purposes.
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In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect
publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or
the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a
publicly traded partnership in the future.
Furthermore, any interpretation of or modification to the U.S. federal income tax laws may be applied retroactively and could
make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships
for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be
enacted. Any similar or future legislative changes could negatively impact the value of an investment in our units. You are urged
to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and
their potential effect on your investment in our units.
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated
as a result of future legislation.
Changes to U.S. federal income tax laws have been proposed in a prior session of Congress that would eliminate certain key
U.S. federal income tax preferences relating to coal exploration and development. These changes include, but are not limited to
(i) repealing capital gains treatment of coal and lignite royalties, (ii) eliminating current deductions and 60-month amortization
for exploration and development costs relating to coal and other hard mineral fossil fuels, and (iii) repealing the percentage depletion
allowance with respect to coal properties. If enacted, these changes would limit or eliminate certain tax deductions that are currently
available with respect to coal exploration and development, and any such change could increase the taxable income allocable to
our unitholders and negatively impact the value of an investment in our units. We are not aware of any current proposals with
regard to these changes.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from
us. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our
activities.
Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than
the cash we distribute, our unitholders are required to pay any federal income taxes and, in some cases, state and local income
taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash
distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that
income.
For our unitholders subject to the passive loss rules, our current operations include portfolio activities (such as our coal and
mineral royalty businesses) and passive activities (such as our soda ash business). Any passive losses we generate will only be
available to offset our passive income generated in the future and will not be available to offset (i) our portfolio income, including
income related to our coal and mineral royalty businesses, (ii) a unitholder’s income from other passive activities or investments,
including investments in other publicly traded partnerships, or (iii) a unitholder’s salary or active business income. Thus, our
unitholders' share of our portfolio income may be subject to federal income tax, regardless of other losses they may receive from
us.
We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including
income and gain from the sale of properties and cancellation of indebtedness income) allocable to our unitholders, and income
tax liabilities arising therefrom may exceed any distributions made with respect to their units.
We may engage in transactions to reduce our leverage and manage our liquidity that would result in income and gain to our
unitholders without a corresponding cash distribution. For example, we may sell assets and use the proceeds to repay existing debt,
in which case, our unitholders could be allocated taxable income and gain resulting from the sale without receiving a cash
distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or
modifications of our existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”)
being allocated to our unitholders as ordinary taxable income. Our unitholders may be allocated income and gain from these
transactions, and income tax liabilities arising therefrom may exceed any distributions we make to our unitholders. The ultimate
tax effect of any such income allocations will depend on the unitholder's individual tax position, including, for example, the
availability of any suspended passive losses that may offset some portion of the allocable income. Our unitholders may, however,
be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against
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any capital losses attributable to the unitholder’s ultimate disposition of its units. Our unitholders are encouraged to consult their
tax advisors with respect to the consequences to them
If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the cost
of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes
or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort
to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of
the positions we take. Any contest by the IRS may materially and adversely impact the market for our units and the price at which
they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner
because the costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some
states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit
adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced .
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit
adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties
and interest) resulting from such audit adjustment directly from us. To the extent possible under these rules, our general partner
may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a
revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although
our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any
resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit,
there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current
unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own
units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes,
penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Distributions in excess of a common unitholder's allocable share of our net
taxable income result in a decrease in the tax basis in such unitholder's common units. Accordingly, the amount, if any, of such
prior excess distributions with respect to the common units sold will, in effect, become taxable income to our common unitholders
if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less
than their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our
unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be
taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. Thus, a unitholder may
recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than
such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to
$3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize
ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally
cannot be offset by any capital loss recognized upon the sale of units.
Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or
business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017,
our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.”
For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or
business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation,
amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with
respect to inventory. If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their
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ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to
limitation on their ability to deduct interest expense incurred by us.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known
as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from
U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable
to them. Further, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, subject to the proposed
aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with
more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged
in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity
separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction).
As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an
investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa.
Tax-exempt entities should consult a tax advisor before investing in our units.
Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our
units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income
effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any
gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result,
distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S.
unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the
sale or disposition of that unit.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to
withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are
required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not
withheld. Because the “amount realized” includes a partner’s share of the partnership’s liabilities, 10% of the amount realized
could exceed the total cash purchase price for the units. However, pending the issuance of final regulations, the IRS has suspended
the application of this withholding rule to transfers of publicly traded interests in publicly traded partnerships. If recently
promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded
interests in publicly traded partnerships effected through a broker, that the obligation to withhold is imposed on the transferor’s
broker and that a partner’s “amount realized” does not include a partner’s share of a publicly traded partnership’s liabilities for
purposes of determining the amount subject to withholding. However, it is not clear when such regulations will be finalized and
if they will be finalized in their current form.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units
purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation
and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of
these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our
common units or result in audit adjustments to our unitholders' tax returns.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction.
The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value
of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, including when we issue additional
units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers
regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our
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common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the
resulting allocations of income, gain, loss and deduction.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units
each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date
a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income,
gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units
each month based upon the ownership of our common units on the first day of each month (the "Allocation Date"), instead of on
the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital
additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other
extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow
a similar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we
have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income,
gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may
be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect
to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a
unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case,
the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to
the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any
of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully taxable as ordinary income. Our unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a loan of their units are urged to consult a tax advisor to determine
whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
As a result of investing in our units, our unitholders are likely subject to state and local taxes and return filing requirements
in jurisdictions where we operate or own or acquire property.
In addition to U.S. federal income taxes, our unitholders are likely subject to other taxes, including state and local taxes,
unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we
conduct business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our
unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these
various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own
property and conduct business in a number of states in the United States. Most of these states impose an income tax on individuals,
corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in
additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal, state and local tax
returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of
such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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ITEM 3. 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, management believes these ordinary course matters will not have
a material effect on our financial position, liquidity or operations. During 2019, we were also involved in the legal proceeding
described below.
In January 2013, we acquired a non-controlling 48.51% general partner interest in OCI Wyoming, L.P. ("OCI LP") and all
of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited
partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko").
The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical
Corporation.
The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by us if certain
performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015.
For those years, we paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment
obligations.
In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical
Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, we exchanged the stock
of OCI Co for a limited partner interest in OCI LP. Following the reorganization, our interest in OCI LP remained at 49%, consisting
of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues, management
or control of OCI LP.
In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC in the District Court of Harris County, Texas, 157th
Judicial District. The complaint alleged that the transactions conducted in 2013 triggered an acceleration of NRP's obligation under
the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of
such amount, together with interest, court costs and attorneys’ fees.
In November 2019, the trial court ruled in our favor in all respects, including that the internal restructuring that occurred did
not trigger an acceleration of the contingent purchase price payment obligation under the purchase agreement with Anadarko.
Accordingly, the trial court ordered that Anadarko take nothing. Anadarko did not appeal the trial court's ruling, and this case is
concluded with no liability to us.
ITEM 4. MINE SAFETY DISCLOSURES
None.
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
PART II
NRP Common Units
Our common units are listed and traded on the NYSE under the symbol "NRP." As of February 10, 2020, there were
approximately 13,180 beneficial and registered holders of our common units. The computation of the approximate number of
unitholders is based upon a broker survey.
Securities Authorized for Issuance under Equity Compensation Plans
The following table shows the securities authorized for issuance under our 2017 Long-Term Incentive Plan at December 31,
2019. The initial number of common units authorized for issuance pursuant to awards under the plan was 800,000.
Plan Category
Equity compensation plans approved by security
holders
Equity compensation plans not approved by
security holders
Total
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights
Weighted-average exercise
price of outstanding
options, warrants and
rights
Number of securities
remaining available for
issuance under equity
compensation plans
(excluding securities
reflected in column (a))
(a)
(b)
(c)
—
n/a
—
—
n/a
—
613,018 (1)
n/a
613,018
(1) As of December 31, 2019, 157,789 phantom units were outstanding under the plan. Each phantom unit represents the right
to receive one common unit, together with associated distribution equivalent rights.
ITEM 6. SELECTED FINANCIAL DATA
The following table shows selected historical financial data for Natural Resource Partners L.P. for the periods and as of the
dates indicated. We derived the information in the following tables from, and the information should be read together with and is
qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in "Item 8. Financial
Statements and Supplementary Data" in this and previously filed Annual Reports on Form 10-K. These tables should be read
together with "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations."
39
Table of Contents
(In thousands, except per unit data)
Total revenues and other income
Asset impairments
Income (loss) from operations
Net income (loss) from continuing
operations
Net income from continuing operations
excluding impairments
Net income (loss) from discontinued
operations
Net income (loss)
Per common unit amounts (basic)
Net income (loss) from continuing
operations
Net income (loss) from discontinued
operations
Net income (loss)
Per common unit amounts (diluted)
Net income (loss) from continuing
operations
Net income (loss) from discontinued
operations
Net income (loss)
Distributions paid per common unit
Average number of common units
outstanding - basic
Average number of common units
outstanding - diluted
Net cash provided by (used in)
Operating activities of continuing
operations
Investing activities of continuing
operations
Financing activities of continuing
operations
Distributable cash flow (2)
Free cash flow (2)
Cash flow cushion (2)
Adjusted EBITDA (2)
Cash, cash equivalents and restricted cash
Total assets
Current portion of long-term debt, net
Long-term debt, net
Long-term lease obligations (3)
Class A convertible preferred units
Partners’ capital
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
For the Year Ended December 31,
2019
263,935
148,214
51,321
$
$
$
2018 (1)
278,512
18,280
192,538
(25,414) $
122,360
122,800
$
140,640
956
$
(24,458) $
17,687
140,047
(4.43) $
0.08
$
(4.35) $
(4.43) $
0.08
$
(4.35) $
$
2.65
7.35
1.42
8.77
5.90
0.86
6.76
1.80
12,260
12,260
12,244
20,234
137,319
8,221
$
$
178,282
7,607
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(253,305) $
$
144,933
$
139,040
$
7,762
$
199,228
$
98,265
$
1,085,907
$
45,776
$
470,422
$
3,506
$
164,587
$
338,963
383,980
183,440
16,080
230,241
206,030
1,341,647
115,184
557,574
(6,839) $
$
$
$
$
$
$
$
$
— $
$
$
164,587
423,481
2017
246,325
2,967
176,559
82,485
85,452
6,182
88,667
4.57
0.50
5.06
3.68
0.28
3.96
1.80
12,232
21,950
112,151
9,807
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2016
279,244
15,861
181,157
90,626
106,487
6,266
96,892
7.28
0.50
7.78
7.28
0.50
7.78
1.80
12,232
12,232
80,243
65,057
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(134,149) $
$
121,958
$
121,324
$
9,248
$
211,483
$
26,980
$
1,389,164
$
79,740
$
729,608
— $
$
$
173,431
265,211
(146,373) $
$
255,172
$
75,970
(29,444) $
$
235,273
$
39,171
$
1,448,649
$
140,037
$
990,234
— $
— $
$
151,530
2015
300,635
378,327
(170,699)
(260,443)
117,884
(311,277)
(571,720)
(20.80)
(24.94)
(45.75)
(20.80)
(24.94)
(45.75)
2.70
12,232
12,232
144,907
15,805
(166,443)
157,815
144,210
(8,339)
240,553
40,244
1,674,865
80,745
1,130,696
—
—
76,336
(1) On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, and all the related amendments
to all open contracts using the modified retrospective method. NRP recognized a $70.5 million cumulative effect of adoption adjustment in the opening
balance of partners' capital on January 1, 2018. Comparative information for the years ended December 31, 2017, 2016 and 2015 have not been restated
and continues to be reported under the standards in effect for those periods.
(2)
See "—Non-GAAP Financial Measures" below.
(3) On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments and recognized assets and liabilities
on its Consolidated Balance Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months.
40
Table of Contents
Non-GAAP Financial Measures
Distributable Cash Flow
Distributable cash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus
distributions from unconsolidated investment in excess of cumulative earnings, proceeds from asset sales and disposals, including
sales of discontinued operations, and return of long-term contract receivables; 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. In addition, DCF presented below is not calculated or presented on the same basis as distributable cash flow as
defined in our partnership agreement, which is used as a metric to determine whether we are able to increase quarterly distributions
to our common unitholders. 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 asses our ability to make cash distributions and
repay debt.
Free Cash Flow
Free cash flow ("FCF") represents net cash provided by (used in) operating activities of continuing operations plus
distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables; less
maintenance and expansion capital expenditures, cash flow used in acquisition costs classified as financing activities and
distributions to non-controlling interest. FCF is calculated before mandatory debt repayments. FCF 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. FCF may not be calculated the same for us as for other companies. FCF 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 our ability to make cash distributions and repay debt.
Cash Flow Cushion
Cash flow cushion represents net cash provided by (used in) operating activities of continuing operations plus distributions
from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables; less maintenance
and expansion capital expenditures, cash flow used in acquisition costs classified as financing activities, distributions to non-
controlling interest, one-time beneficial items, mandatory Opco debt repayments, preferred unit distributions and common unit
distributions. Cash flow cushion 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. Cash flow cushion is a supplemental liquidity measure
used by our management to assess our ability to make or raise cash distributions to our common and preferred unitholders and our
general partner and repay debt or redeem preferred units.
41
Table of Contents
The following table reconciles net cash provided by operating activities of continuing operations (the most comparable
GAAP financial measure) to DCF, FCF and cash flow cushion for the years ended December 31, 2019, 2018, 2017, 2016, and
2015:
Distributable cash flow
$
144,933
$
383,980
$
121,958
$
255,172
$
(In thousands)
Net cash provided by operating
activities of continuing operations
Add: distributions from
unconsolidated investment in
excess of cumulative earnings
Add: proceeds from asset sales and
disposals
Add: proceeds from sale of
discontinued operations
Add: return of long-term contract
receivables
Less: maintenance capital
expenditures
Less: distributions to non-
controlling interest
Less: proceeds from asset sales and
disposals
Less: proceeds from sale of
discontinued operations
Less: expansion capital
expenditures
Less: acquisition costs classified as
financing activities
Less: cash flow from one-time
Hillsboro litigation settlement
Less: mandatory Opco debt
repayments
Less: preferred unit distributions
and redemption of PIK units
Less: common unit distributions
2019
2018
2017
2016
2015
For the Year Ended December 31,
$
137,319
$
178,282
$
112,151
$
80,243
$
144,907
—
6,500
2,097
2,449
5,646
1,151
—
—
62,117
13,605
(629)
198,091
—
109,872
1,743
3,061
3,010
2,968
—
—
—
—
—
—
(28)
—
—
2,463
(416)
(2,744)
157,815
(6,500)
(2,449)
(1,151)
(62,117)
(13,605)
629
(198,091)
(22)
—
—
—
—
—
517
(109,872)
—
(7,213)
75,970
—
—
—
$
144,210
—
(25,000)
—
—
—
(68,128)
(80,765)
(80,765)
(82,949)
(80,791)
(30,000)
(33,150)
(39,109)
(22,486)
16,080
$
(8,844)
(22,467)
9,248
$
—
(22,465)
(29,444) $
—
(71,758)
(8,339)
Free cash flow
$
139,040
$
183,440
$
121,324
$
Cash flow cushion
$
7,762
$
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Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) from continuing operations less
equity earnings from unconsolidated investment, net income attributable to non-controlling interest and gain on reserve swap; plus
total distributions from unconsolidated investment, interest expense, net, debt modification expense, loss on extinguishment of
debt, 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. In addition, Adjusted EBITDA presented below is not calculated or presented on the
same basis as Consolidated EBITDA as defined in our partnership agreement or Consolidated EBITDDA as defined in Opco's
debt agreements. See "Item 8. Financial Statements and Supplementary Data—Note 12. Debt, Net" included elsewhere in this
Annual Report on Form 10-K for a description of Opco’s debt agreements. 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.
The following table reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure)
to Adjusted EBITDA for the years ended December 31, 2019, 2018, 2017, 2016, and 2015:
(In thousands)
Net income (loss) from continuing
operations
Less: equity earnings from
unconsolidated investment
Less: net income attributable to
non-controlling interest
Less: gain on reserve swap
Add: total distributions from
unconsolidated investment
Add: interest expense, net
Add: debt modification expense
Add: loss on extinguishment of
debt
Add: depreciation, depletion and
amortization
Add: asset impairments
Adjusted EBITDA
2019
2018
2017
2016
2015
For the Year Ended December 31,
$
(25,414) $
122,360
$
82,485
$
90,626
$
(260,443)
(47,089)
(48,306)
(40,457)
(40,061)
(49,918)
—
—
31,850
47,453
—
29,282
14,932
148,214
(510)
—
46,550
70,178
—
—
21,689
18,280
—
—
49,000
82,028
7,939
4,107
23,414
2,967
—
—
46,550
90,531
—
—
31,766
15,861
$
199,228
$
230,241
$
211,483
$
235,273
$
—
(9,290)
46,795
89,744
—
—
45,338
378,327
240,553
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
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
• Inflation
• Environmental Regulation
• Related Party Transactions
• Summary of Critical Accounting Estimates
• Recent Accounting Standards
As used in this Item 7, 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. NRP Finance
Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes due
2025 (the "2025 Senior Notes").
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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 and other natural resources and own a
non-controlling 49% interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining and soda ash production business.
Our common units trade on the New York Stock Exchange under the symbol "NRP." Our business is organized into two operating
segments:
Coal Royalty and Other—consists primarily of coal royalty properties and coal-related transportation and processing assets.
Other assets include industrial mineral royalty properties, aggregates royalty properties, oil and gas royalty properties and timber.
Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Northern Powder River Basin in the United States.
Our industrial minerals and aggregates properties are located in various states across the United States, our oil and gas royalty
assets are primarily located in Louisiana and our timber assets are primarily located in West Virginia.
Soda Ash—consists of our 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining and soda ash production
business located in the Green River Basin of 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.
Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these
departments include interest and financing, corporate headquarters and overhead, centralized treasury, legal and accounting and
other corporate-level activity not specifically allocated to a segment.
We remain focused on strengthening our balance sheet and maintaining sufficient liquidity to manage our business through
periods of volatility in commodity prices. We devote significant amounts of cash each year to make mandatory amortization
payments on the Opco Senior Notes as well as to make distributions on our preferred units and common units. Accordingly,
preserving the financial flexibility to respond to changes in market conditions while continuing to service our debt and make
distributions to unitholders is one of our key objectives.
Our financial results by segment for the year ended December 31, 2019 are as follows:
Operating Segments
(In thousands)
Revenues and other income
Net income (loss) from continuing operations
Asset impairments
Net income (loss) from continuing operations excluding asset
impairments
Adjusted EBITDA (1)
Cash flow provided by (used in) continuing operations
Operating activities
Investing activities
Financing activities
Distributable cash flow (1)
Free cash flow (1)
Cash flow cushion (1)
Coal Royalty
and Other
$ 216,846
$
21,211
148,214
$ 169,425
$ 184,357
$ 178,863
8,221
$
$
— $
$ 187,106
$ 180,584
$
$
N/A
$
$
$
$
$
$
Soda Ash
Corporate
and
Financing
Total
47,089
46,840
—
— $ 263,935
$
$ (93,465) $ (25,414)
148,214
—
46,840
31,601
$ (93,465) $ 122,800
$ (16,730) $ 199,228
31,601
$ (73,145) $ 137,319
— $
8,221
— $
— $ (253,305) $ (253,305)
$ (73,145) $ 144,933
$ (73,145) $ 139,040
7,762
N/A $
31,601
31,601
N/A
(1) See "Item 6. Selected Financial Data" for additional information regarding non-GAAP financial measures and reconciliations
to the most comparable GAAP financial measures.
45
Table of Contents
Current Results/Market Commentary
Coal Royalty and Other Business Segment
Our lessees sold 23.7 million tons of coal from our properties in 2019 and we derived approximately 65% of our coal royalty
revenues and approximately 50% of our coal royalty sales volumes from metallurgical coal during the year. We experienced strong
coal realizations from our lessees during the first half of 2019, but weakened coal markets and lower activity at certain of our
properties negatively impacted our results in the second half of the year. The current market downturn and lessee bankruptcies are
expected to put downward pressure on our performance in the coming months.
The market for metallurgical coal weakened and prices for metallurgical coal sold from our properties declined in 2019. The
domestic market for thermal coal remains challenged by low natural gas prices, pressure over emissions and climate change and
increasing use of renewable energy. In addition, the export market for thermal coal has weakened due to a combination of lower
demand from European utilities, competition from international producers and increasing supply of LNG. While we expect thermal
coal will continue to have a role in providing global economies and populations with affordable and reliable energy, we expect
these headwinds facing the U.S thermal coal industry will continue.
We remain cautious about the financial position of U.S. coal producers with over-leveraged capital structures and the state
of the domestic and global coal markets generally. The current price environment along with limited access to capital has taken a
toll on a number of producers. Four of our lessees filed for protection under the U.S. Bankruptcy Code in 2019, and other lessees
continue to face challenges. Foresight Energy LP ("Foresight Energy"), which is our largest lessee, has agreed to a forbearance
period with its lenders and is engaging with other contract counterparties to evaluate restructuring options. To the extent Foresight
Energy determines to idle operations on our properties for a prolonged period or to shut any of its mines on our properties down
permanently, or to the extent we agree to amend the terms of our leases with them to facilitate their continued operations on our
properties, our business could be adversely affected. Accordingly, we remain focused on further strengthening our liquidity and
balance sheet.
Soda Ash Business Segment
Ciner Wyoming's results are primarily affected by the global supply of and demand for soda ash, which in turn directly
impacts the prices Ciner Wyoming and other producers charge for its products. Demand for soda ash in the United States is driven
in a large part by economic growth and activity levels in the end markets that the glass-making industry serve, such as the automotive
and construction industries. Because the United States is a well-developed market for soda ash, we expect that domestic supply
of and demand for soda ash will remain stable for the near future. Soda ash demand in international markets has continued to grow
in conjunction with GDP. We expect that future global economic growth will positively influence global demand and pricing over
the long term, which will likely result in increased exports, primarily from the United States, Turkey and to a limited extent, from
China, the largest suppliers of soda ash to international markets. Over the nearer term, Ciner Wyoming could face increased costs
and competition for customers as a result of its planned exit from ANSAC at the end of 2021.
While the performance of the underlying business remains stable, Ciner Wyoming has announced that it will commence a
significant capacity expansion capital project soon that it intends to fund in part by reinvesting cash that would otherwise be
distributed to its partners. As a result, we expect for the cash distributions we receive from Ciner Wyoming to remain at approximately
$25 million to $28 million per year until the project is funded. We believe that we will benefit over the long-term from increased
productivity and cash distributions from Ciner Wyoming’s operations following completion of this capital project.
Business Outlook
We expect the challenges described above to continue to negatively impact our results. However, we believe the progress
made to strengthen our financial profile in recent years positions us well to navigate this downturn.
46
Table of Contents
Results of Operations
Year Ended December 31, 2019 and 2018 Compared
Revenues and Other Income
The following table includes our revenues and other income by operating segment:
Operating Segment (In thousands)
Coal Royalty and Other
Soda Ash
Total
For the Year Ended December 31,
2019
2018
Increase
(Decrease)
Percentage
Change
$
$
216,846
47,089
263,935
$
$
230,206
48,306
278,512
$
$
(13,360)
(1,217)
(14,577)
(6)%
(3)%
(5)%
The changes in revenues and other income is discussed for each of the operating segments below:
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Table of Contents
Coal Royalty and Other
The following table presents coal sales volumes, coal royalty revenue per ton and coal royalty revenues by major coal
producing region, the significant categories of other revenues and other income:
For the Year Ended December 31,
2019
2018
Increase
(Decrease)
Percentage
Change
(In thousands, except per ton data)
Coal sales volumes (tons)
Appalachia
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder River Basin
Total coal sales volumes
Coal royalty revenue per ton
Appalachia
Northern
Central
Southern
Illinois Basin
Northern Powder River Basin
Combined average coal royalty revenue per ton
Coal royalty revenues
Appalachia
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder River Basin
Unadjusted coal royalty revenues
Coal royalty adjustment for minimum leases
Total coal royalty revenues
Other revenues
Production lease minimum revenues
Minimum lease straight-line revenues
Property tax revenues
Wheelage revenues
Coal overriding royalty revenues
Lease amendment revenues
Aggregates royalty revenues
Oil and gas royalty revenues
Other revenues
Total other revenues
Coal royalty and other
Transportation and processing services revenues
Gain on litigation settlement
Gain on asset sales and disposals
Total Coal Royalty and Other segment revenues and other income
$
48
3,460
13,377
1,670
18,507
2,201
3,036
23,744
1.96
5.53
6.69
4.66
2.90
4.67
6,775
73,960
11,169
91,904
10,255
8,809
110,968
(1,356)
109,612
24,068
14,910
6,287
5,880
13,496
7,991
4,265
3,031
1,529
81,457
191,069
19,279
—
6,498
216,846
$
$
$
$
$
$
$
3,187
14,997
1,710
19,894
2,739
4,313
26,946
2.74
5.62
7.20
4.63
2.65
4.80
8,719
84,302
12,312
105,333
12,673
11,445
129,451
(110)
129,341
8,207
2,362
5,422
6,484
13,878
—
4,739
6,608
1,837
49,537
178,878
23,887
25,000
2,441
230,206
$
$
$
$
$
$
$
273
(1,620)
(40)
(1,387)
(538)
(1,277)
(3,202)
(0.78)
(0.09)
(0.51)
0.03
0.25
(0.13)
(1,944)
(10,342)
(1,143)
(13,429)
(2,418)
(2,636)
(18,483)
(1,246)
(19,729)
15,861
12,548
865
(604)
(382)
7,991
(474)
(3,577)
(308)
31,920
12,191
(4,608)
(25,000)
4,057
(13,360)
9 %
(11)%
(2)%
(7)%
(20)%
(30)%
(12)%
(28)%
(2)%
(7)%
1 %
9 %
(3)%
(22)%
(12)%
(9)%
(13)%
(19)%
(23)%
(14)%
(1,133)%
(15)%
193 %
531 %
16 %
(9)%
(3)%
100 %
(10)%
(54)%
(17)%
64 %
7 %
(19)%
(100)%
166 %
(6)%
$
$
$
$
$
$
Table of Contents
Coal Royalty Revenues
Total coal royalty revenues decreased $19.7 million from 2018 to 2019 driven primarily by lower coal sales volumes. The
discussion of these decreases by region is as follows:
• Appalachia: Sales volumes decreased 7% and revenues decreased $13.4 million year-over-year. Northern Appalachia
includes our Hibbs Run property that has significant sales volumes but a low fixed royalty rate per ton and as a result has
a minimal impact on our revenues. Excluding Hibbs Run, sales volumes from our Appalachia properties decreased
approximately 11% primarily as a result of weakened coal markets and the temporary idling of certain mines due to lessee
bankruptcies.
•
Illinois Basin: Sales volumes decreased 20% and coal royalty revenues decreased $2.4 million primarily due to weakening
of the thermal export market and lower domestic thermal coal demand in 2019 along with flooding and high water
throughout the river systems that affected transportation logistics during the first half of 2019, including at the Convent
Marine Terminal on the Gulf of Mexico.
• Northern Powder River Basin: Sales volumes decreased 30% and coal royalty revenues decreased $2.6 million
primarily due to our lessee mining off of our property in accordance with its mine plan in 2019, partially offset by a 9%
increase in sales prices year-over-year.
Other Revenues
Total other revenues increased $31.9 million from 2018 to 2019 primarily due to:
•
•
$15.9 million increased production lease minimum revenues primarily as a result of increased lessee forfeitures of
recoupable balances from minimums paid in prior periods.
$12.5 million increased minimum lease straight-line revenues primarily related to our Hillsboro property that we began
to recognize in 2019 after the completion of the Hillsboro litigation settlement with Foresight.
•
$8.0 million of lease amendment revenues during the year ended December 31, 2019.
Transportation and Processing Services Revenues
Transportation and processing services revenues decreased $4.6 million primarily due to weakened demand for Illinois Basin
coal that resulted in fewer tons being transported out of our Illinois Basin transportation and processing assets during the year
ended December 31, 2019.
Gain on Litigation Settlement
Gain on litigation settlement in the year ended December 31, 2018 related to a one-time payment of $25.0 million we received
from Foresight Energy to settle the Hillsboro lawsuit.
Gain on Asset Sales and Disposals
Gain on asset sales and disposals increased $4.1 million from 2018 to 2019 primarily due to a disposal of certain mineral
right assets during the third quarter of 2019.
Soda Ash
Revenues and other income related to our Soda Ash segment decreased $1.2 million primarily due to Ciner Wyoming's
settlement of a royalty dispute in the second quarter of 2018 that resulted in $12.7 million of income in the prior year, partially
offset by an increase in production and sales volumes and increased domestic and international sales prices in the year ended
December 31, 2019 compared to the prior year.
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Operating and Other Expenses
The following table presents the significant categories of our consolidated operating and other expenses:
(In thousands)
Operating expenses
Operating and maintenance expenses
Depreciation, depletion and amortization
General and administrative expenses
Asset impairments
Total operating expenses
Other expenses, net
Interest expense, net
Loss on extinguishment of debt
Total other expenses, net
For the Year Ended
December 31,
2019
2018
Increase
(Decrease)
Percentage
Change
$
$
32,738
14,932
16,730
148,214
$
29,509
21,689
16,496
18,280
3,229
(6,757)
234
129,934
$
212,614
$
85,974
$
126,640
$
$
47,453
29,282
76,735
$
$
70,178
—
70,178
$
$
(22,725)
29,282
6,557
11 %
(31)%
1 %
711 %
147 %
(32)%
100 %
9 %
Total operating expenses increased by $126.6 million primarily due to the following:
• Asset impairments increased $129.9 million from 2018 to 2019. Asset impairments in the year ended December 31, 2019
primarily resulted from deterioration in thermal coal markets, lessee capital constraints, thermal coal lease terminations,
and expectations of further reductions in global and domestic thermal coal demand due to low natural gas prices and
continued pressure on the electric power generation industry over emissions and climate change, resulting in reductions
in expected cash flows (combination of lower expected coal sales volumes, sales prices, minimums and/or life of mine
assumptions) on certain of our mineral rights and intangible assets. Asset impairments in the year ended December 31,
2018 primarily related to a $13.0 million impairment of an aggregates property that we own and lease to our former
construction aggregates business, which mines, produces and sells the aggregates, in addition to $5.3 million of
impairments related to certain of our coal properties.
• Operating and maintenance expenses include costs to manage the Coal Royalty and Other and Soda Ash segments and
primarily consist of royalty, tax, employee-related and legal costs and bad debt expense. These costs increased $3.2 million
primarily due to bad debt expense recognized in the second quarter of 2019 related to certain of our Coal Royalty and
Other receivables, partially offset by lower legal costs and lower overriding royalty interest fees.
• Depreciation, depletion and amortization expense decreased $6.8 million due to lower coal sales volumes at certain
properties.
Total other expenses, net increased $6.6 million primarily due to the following:
• Loss on extinguishment of debt was $29.3 million for the year ended December 31, 2019 and related to the 105.25%
premium paid to redeem the 2022 Senior Notes in the second quarter of 2019 as well as the write-off of unamortized debt
issuance costs and debt discount related to the 2022 Senior Notes.
•
Interest expense, net decreased $22.7 million primarily due to lower debt balances in 2019 as a result of debt repayments.
Income from Discontinued Operations
Income from discontinued operations decreased $16.7 million primarily as a result of the $13.1 million gain on sale of our
construction aggregates business in the year ended December 31, 2018 in addition to $4.7 million of income generated by this
business in 2018 prior to the sale.
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Table of Contents
Adjusted EBITDA (Non-GAAP Financial Measure)
The following table reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure)
to Adjusted EBITDA by business segment:
For the Year Ended (In thousands)
December 31, 2019
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate and
Financing
Total
Net income (loss) from continuing operations
$
21,211
$
Less: equity earnings from unconsolidated investment
Add: total distributions from unconsolidated investment
Add: interest expense, net
Add: loss on extinguishment of debt
Add: depreciation, depletion and amortization
Add: asset impairments
—
—
—
—
14,932
148,214
$
46,840
(47,089)
31,850
—
—
—
—
Adjusted EBITDA
December 31, 2018
$
184,357
$
31,601
$
(93,465) $
—
—
47,453
29,282
—
—
(16,730) $
Net income (loss) from continuing operations
$
160,728
$
Less: equity earnings from unconsolidated investment
Less: net income attributable to non-controlling interest
Add: total distributions from unconsolidated investment
Add: interest expense, net
Add: depreciation, depletion and amortization
Add: asset impairments
Adjusted EBITDA
—
(510)
—
—
21,689
18,280
48,306
(48,306)
—
46,550
—
—
—
$
(86,674) $
—
—
—
70,178
—
—
(16,496) $
$
200,187
$
46,550
$
(25,414)
(47,089)
31,850
47,453
29,282
14,932
148,214
199,228
122,360
(48,306)
(510)
46,550
70,178
21,689
18,280
230,241
Adjusted EBITDA decreased $31.0 million primarily due to the following:
• Coal Royalty and Other Segment
Adjusted EBITDA decreased $15.8 million primarily as a result of the decrease in revenues and other income
driven by the weakened coal markets and the $25 million gain on litigation settlement in 2018.
•
Soda Ash Segment
Adjusted EBITDA decreased $14.9 million as a result of lower cash distributions received from Ciner Wyoming
during the year ended December 31, 2019. The managing partner of Ciner Wyoming decided to reduce
distributions during 2019 to fund a multi-year capacity expansion project that is expected to result in higher
earnings and distributions. NRP expects to receive approximately $25 million to $28 million of annual cash
distributions from Ciner Wyoming until the project is funded.
See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of Adjusted EBITDA.
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Distributable Cash Flow ("DCF"), Free Cash Flow ("FCF") and Cash Flow Cushion (Non-GAAP Financial Measures)
The following table presents the three major categories of the statement of cash flows by business segment:
For the Year Ended (In thousands)
December 31, 2019
Cash flow provided by (used in) continuing operations
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate and
Financing
Total
Operating activities
Investing activities
Financing activities
$
178,863
$
31,601
$
8,221
—
—
—
(73,145) $
—
(253,305)
137,319
8,221
(253,305)
December 31, 2018
Cash flow provided by (used in) continuing operations
Operating activities
Investing activities
Financing activities
$
$
212,394
5,510
—
$
44,453
2,097
—
(78,565) $
—
(6,839)
178,282
7,607
(6,839)
The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial
measure) by business segment to DCF, FCF and cash flow cushion:
For the Year Ended (In thousands)
December 31, 2019
Net cash provided by (used in) operating activities of
continuing operations
Add: proceeds from asset sales and disposals
Add: proceeds from sale of discontinued operations
Add: return of long-term contract receivable
Distributable cash flow
Less: proceeds from asset sales and disposals
Less: proceeds from sale of discontinued operations
Less: expansion capital expenditures
Free cash flow
Less: mandatory Opco debt repayments
Less: preferred unit distributions
Less: common unit distributions
Cash flow cushion
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate and
Financing
Total
$
178,863
$
31,601
$
6,500
—
1,743
187,106
(6,500)
—
(22)
180,584
$
$
—
—
—
$
31,601
$
—
—
—
$
31,601
$
(73,145) $
—
—
—
(73,145) $
—
—
—
(73,145) $
$
137,319
6,500
(629)
1,743
144,933
(6,500)
629
(22)
139,040
(68,128)
(30,000)
(33,150)
7,762
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Table of Contents
For the Year Ended (In thousands)
December 31, 2018
Net cash provided by (used in) operating activities of
continuing operations
Add: distributions from unconsolidated investment in
excess of cumulative earnings
Add: proceeds from asset sales and disposals
Add: proceeds from sale of discontinued operations
Add: return of long-term contract receivable
Distributable cash flow
Less: proceeds from asset sales and disposals
Less: proceeds from sale of discontinued operations
Free cash flow
Less: cash flow from one-time Hillsboro litigation
settlement
Less: mandatory Opco debt repayments
Less: preferred unit distributions and redemption of PIK
units
Less: common unit distributions
Cash flow cushion
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate and
Financing
Total
$
212,394
$
44,453
$
(78,565) $
178,282
—
2,449
—
3,061
2,097
—
—
—
$
217,904
$
46,550
$
(2,449)
—
—
—
$
215,455
$
46,550
$
—
—
—
—
(78,565) $
2,097
2,449
198,091
3,061
383,980
—
(2,449)
—
(78,565) $
(198,091)
183,440
(25,000)
(80,765)
(39,109)
(22,486)
16,080
$
DCF and FCF decreased $239.0 million and $44.4 million, respectively, primarily due to the following:
• Coal Royalty and Other Segment
DCF and FCF decreased $30.8 million and $34.9 million, respectively, primarily due to a one-time $25 million
payment we received from Foresight Energy to settle the Hillsboro lawsuit in 2018 and lower coal royalty
revenues as described above, partially offset by increased cash from the receipt of lease amendment fees and
Hillsboro minimum payments in 2019.
•
Soda Ash Segment
DCF and FCF decreased $14.9 million as a result of lower cash distributions received from Ciner Wyoming
during the year ended December 31, 2019.
• Corporate and Financing Segment
DCF and FCF increased $5.4 million primarily due to lower cash paid for interest in 2019 as a result of lower
debt balances during 2019.
Total DCF for the year ended December 31, 2018 was also impacted by the $198.1 million proceeds from the sale of our
construction aggregates business in 2018.
Cash flow cushion decreased $8.3 million as a result of the decrease in FCF discussed above (excluding the impact of the
$25 million Hillsboro payment) and a $10.7 million increase in common unit distributions made in 2019 primarily as a result of
a one-time special distribution of $0.85 per common unit. These decreases in 2019 cash flow cushion were partially offset by a
$12.6 million decrease in mandatory Opco debt repayments as a result of the lower principal balances on the Opco Senior Notes
and a $9.1 million decrease in preferred unit distributions primarily as a result of the $8.8 million redemption of PIK units in 2018.
See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of distributable cash flow, free
cash flow and cash flow cushion.
For discussion of our Results of Operations comparing 2018 to 2017, refer to our 2018 Annual Report on Form 10-K filed
March 7, 2019 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
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Liquidity and Capital Resources
Current Liquidity
As of December 31, 2019, we had total liquidity of $198.3 million, consisting of $98.3 million of cash and cash equivalents
and $100.0 million in borrowing capacity under our Opco Credit Facility.
Cash Flows
Year Ended December 31, 2019 and 2018 Compared
Cash flows provided by operating activities decreased $51.6 million, from $188.9 million in the year ended December 31,
2018 to $137.3 million in the year ended December 31, 2019 primarily related to a one-time $25 million payment we received
from Foresight Energy in 2018 to settle the Hillsboro lawsuit, $12.6 million of lower cash distributions received from Ciner
Wyoming in 2019, $10.6 million lower cash provided as a result of the sale of our construction aggregates business in the fourth
quarter of 2018 and lower coal royalty revenues driven by weakened coal markets and the temporary idling of certain mines. These
decreases in cash provided by operating activities were partially offset by the collection of Hillsboro minimum payments, lease
amendment fees and $6.4 million lower cash paid for interest as a result of lower debt balances in 2019.
Cash flows provided by investing activities decreased $183.0 million, from $190.6 million in the year ended December 31,
2018 to $7.6 million in the year ended December 31, 2019. Cash flows from discontinued operations decreased $183.7 million as
a result of the $198.1 million proceeds received from the sale of our construction aggregates business in December 2018, partially
offset by $10.9 million of construction aggregates capital expenditures during 2018. Cash flows from continuing operations was
relatively flat year-over-year as the $4.1 million increase in proceeds from asset sales and disposals was partially offset by a portion
of our distribution from Ciner Wyoming classified as an investing activity in 2018 and a lower return of our long-term contract
receivable in 2019.
Cash flows used in financing activities increased $49.3 million, from $203.3 million in the year ended December 31, 2018
to $252.7 million in the year ended December 31, 2019. In the second quarter of 2019, we extended the maturity date of the $100
million Opco Credit Facility to April 2023 and issued $300 million of a new series of 9.125% senior notes due 2025. We used the
net proceeds from this offering, together with $76 million of cash on hand to redeem all of our 2022 Senior Notes. As a result of
these transactions, our outstanding debt was reduced, our annual interest expense has decreased, and our debt maturities were
extended. Significant increases in cash flow used in financing activities included the following:
•
•
•
•
•
$345.6 million used for the redemption of our 2022 Senior Notes in the second quarter of 2019;
$36.7 million increase in payments on the Opco Senior Notes primarily as a result of the prepayment made using proceeds
from the sale of our construction aggregates business;
$35.0 million less borrowings on our Opco Credit Facility in 2019 compared to the prior year period;
$26.2 million increase in debt issuance costs and other primarily related to the 2019 debt refinancings; and
$10.7 million increase in common unit distributions made in 2019 primarily as a result of a one-time special distribution
of $0.85 per common unit.
These increases in cash flows used in financing activities were partially offset by the following:
•
•
•
$300 million provided by the issuance of the 2025 Senior Notes in the second quarter of 2019;
$95 million less cash used in 2019 compared to the prior year as a result of the repayment of the Opco Credit Facility
during the fourth quarter of 2018; and
$8.8 million less cash used in 2019 compared to the prior year as a result of the redemption of preferred units paid-in-
kind in the first quarter of 2018.
For discussion of our Cash Flows comparing 2018 to 2017, refer to our 2018 Annual Report on Form 10-K filed March 7,
2019 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
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Capital Resources and Obligations
Debt, Net
We had the following debt outstanding as of December 31, 2019 and 2018:
(In thousands)
Current portion of long-term debt, net
Long-term debt, net
Total debt, net
December 31,
2019
2018
$
$
45,776
470,422
516,198
$
$
115,184
557,574
672,758
We have been 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 "Item 8. Financial Statements and Supplementary Data—Note 12. Debt, Net" in this Annual Report on Form 10-K.
Long-Term Contractual Obligations
The following table reflects our long-term, non-cancelable contractual obligations as of December 31, 2019:
Contractual Obligations (In thousands)
NRP:
Long-term debt principal payments (1)
Long-term debt interest payments (1)
Opco:
Long-term debt principal payments
(including current maturities) (2)
Long-term debt interest payments (3)
Rental leases (4)
Total
Total
2020
2021
2022
2023
2024
Thereafter
Payments Due by Period
$ 300,000
$
— $
— $
— $
— $
— $ 300,000
150,563
27,375
27,375
27,375
27,375
27,375
13,688
224,056
39,865
14,012
46,176
12,447
483
39,396
39,396
39,396
31,028
9,868
483
7,631
483
5,020
483
2,724
483
28,664
2,175
11,597
$ 728,496
$ 86,481
$ 77,122
$ 74,885
$ 72,274
$ 61,610
$ 356,124
(1) The amounts indicated in the table include principal and interest due on NRP’s 2025 Senior Notes.
(2) The amounts indicated in the table include principal due on Opco’s senior notes.
(3) The amounts indicated in the table include interest due on Opco’s senior notes and the 0.50% annual commitment fee on the
unused portion of the Opco Credit Facility, which matures in April 2023. At December 31, 2019 we did not have any
borrowings outstanding under the Opco Credit Facility and had $100 million in available borrowing capacity.
(4) On January 1, 2019, Opco entered into a lease agreement for the rental of office space from Western Pocahontas Properties
Limited Partnership for $0.5 million per year. Not included in this table is approximately $0.3 million of annual operating
expenses Opco is obligated to pay to Western Pocahontas Properties Limited Partnership in connection with this lease. The
lease has a five-year base term and five additional five-year renewal options. Upon lease commencement and as of
December 31, 2019, the Partnership was reasonably certain to exercise all renewal options included in the lease and have
included rental payments in the table through 2048.
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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Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for
the years ended December 31, 2019, 2018 and 2017.
Environmental Regulation
For additional information on environmental regulation that may have a material impact on our business, see "Items 1. and
2. Business and Properties—Regulation and Environmental Matters."
Related Party Transactions
The information required by this Item is included under "Item 8. Financial Statements and Supplementary Data—Note 14.
Related Party Transactions" and "Item 13. Certain Relationships and Related Transactions, and Director Independence" in this
Annual Report on Form 10-K and is incorporated by reference herein.
Summary of Critical Accounting Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses. See "Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting
Policies" in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significant accounting policies.
The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated
Financial Statements. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates.
Revenues
Coal Royalty and Other Segment Revenues
Royalty-based leases. Approximately two-thirds of the our royalty-based leases have initial terms of five to 40 years, with
substantially all lessees having the option to extend the lease for additional terms. For these types of leases, the lessees generally
make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral mined and
sold. Most of our coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts, either made
in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally
range from three to five years.
In accordance with previous accounting standards in effect prior to January 1, 2018, we recognized all coal and aggregates
royalty revenues over the lease term based on production. The recognition of revenue from minimum payments was deferred until
either recoupment through royalty production occurred or when the recoupment period expired for unrecouped minimums. In
accordance with the accounting standard in effect subsequent to January 1, 2018 ("ASC 606"), we have defined our coal and
aggregates royalty lease performance obligation as providing the lessee the right to mine and sell our coal or aggregates over the
lease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production
would exceed consideration expected to be received from minimum payments over the lease term.
As a result of this evaluation, revenue recognition from our royalty-based leases is based on either production or minimum
payments as follows:
• Production Leases: Leases for which we expect that consideration from production will be greater than consideration
from minimums over the lease term. Revenue recognition for these leases is recognized over time based on production
as coal royalty revenues or aggregates royalty revenues, as applicable. Deferred revenue from minimums is recognized
as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period
expires. In addition, we recognize breakage revenue from minimums when we determine that recoupment is remote.
This breakage revenue is included in production lease minimum revenues.
• Minimum Leases: Leases for which we expect that consideration from minimums will be greater than consideration
from production over the lease term. Revenue recognition for these leases is recognized straight-line over the lease
term based on the minimum consideration amount as minimum lease straight-line revenues.
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This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease.
Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of
volume of hydrocarbons sold by lessees and the corresponding revenues from those sales. Also included within oil and gas royalty
revenues are lease bonus payments, which are generally paid upon the execution of a lease. We also have overriding royalty revenue
interests in coal reserves. Revenues from these interests is recognized over time based on when the coal is sold.
Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property we own that is
recognized over time as transportation across our property occurs.
Other revenues. Other revenues consists primarily of rental payments and surface damage fees related to certain land we
own and is recognized straight-line over time as it is earned. Other revenues also include property tax revenues. The majority of
property taxes paid on our properties are reimbursable by the lessee and are recognized on a gross basis over time which reflects
the reimbursement of property taxes by the lessee. Property taxes we pay are included in operating and maintenance expenses on
our Consolidated Statements of Comprehensive Income (Loss).
Transportation and processing services revenues. We own transportation and processing infrastructure that is leased to third
parties for throughput fees. Revenue is recognized over time based on the coal tons transported over the beltlines or processed
through the facilities.
Contract Modifications
Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A
majority of our contract modifications pertain to our coal and aggregates royalty contracts and include, but are not limited to,
extending the lease term, changes to royalty rates, floor prices or minimum consideration, assignment of the contract or forfeiture
of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred and recognized
straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited
minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized
in lease amendment revenues within coal royalty and other revenues on our Consolidated Statements of Comprehensive Income
(Loss) while modifications in royalty rates and minimums will be recognized prospectively in accordance with the above lease
classification.
Contract Assets and Liabilities from Contracts with Customers
Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes
unconditional. Receivables are recognized when the minimums are contractually owed, production occurs or minimums are accrued
for based on the passage of time.
Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time.
The current portion of deferred revenue relates to deferred revenue on minimum leases and lease amendment fees that are to be
recognized as revenue on a straight-line basis over the next twelve months. The long-term portion of deferred revenue relates to
deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-line basis
beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as coal
royalty revenues from production leases over the next twelve months, we are unable to estimate the current portion of deferred
revenue.
Equity in Earnings of Ciner Wyoming.
We account for non-marketable equity investments using the equity method of accounting if the investment gives it the ability
to exercise significant influence over, but not control of, an investee. Our 49% investment in Ciner Wyoming is accounted for
using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent
additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the
investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortized over its estimated
useful life. The carrying value in Ciner Wyoming is recognized in equity in unconsolidated investment on our Consolidated Balance
Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming and amortization of the basis difference is recognized in
equity in earnings of Ciner Wyoming on the Consolidated Statements of Comprehensive Income (Loss). We decrease our investment
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for our proportional share of distributions received from Ciner Wyoming. These cash flows are reported utilizing the cumulative
earnings approach. Under this approach, distributions received are considered returns on investment and classified as operating
cash inflows unless the cumulative distributions received exceed our cumulative equity in earnings. The excess of cumulative
distributions received over our cumulative equity in earnings are considered returns of investment and classified as investing cash
inflows.
Mineral Rights
Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the
assets acquired. Coal and aggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined
in relation to the net cost of the mineral properties and estimated proven and probable tonnage as defined by the SEC’s Industry
Guide 7 and estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers
in the estimation of our proved reserves include, but are not limited to, drill logs, geophysical logs, geologic maps including
isopach, mine, and coal quality, cross sections, statistical analysis, and available public production data. There are numerous
uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control.
Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which
may, if incorrect, result in an estimate that varies considerably from actual results.
Asset Impairment
We have developed procedures to evaluate our long-lived assets for possible impairment periodically or whenever events
or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include,
but are not limited to, specific events such as a reduction in economically recoverable reserves or production ceasing on a property
for an extended period. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and
disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usually
determined based upon the present value of the projected future cash flow compared to the asset's net book value. We believe our
estimates of cash flows and discount rates are consistent with those of principal market participants.
We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s
judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When
evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of
the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and
management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair
value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted
market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by
principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.
Recent Accounting Standards
For a discussion of recent accounting pronouncements, see the applicable section of "Item 8. Financial Statements and
Supplementary Data—Note 2. Summary of Significant Accounting Policies" in the audited consolidated financial statements
included elsewhere in this Annual Report on Form 10-K.
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ITEM 7A. 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
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend
substantially on prevailing commodity prices. Historically, coal prices have been volatile, with prices fluctuating widely, and they
are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results.
In particular, substantially lower prices would significantly reduce revenues and could potentially trigger an impairment of our
coal properties or a violation of certain financial debt covenants. Because substantially all of our reserves are coal, changes in coal
prices have a more significant impact on our financial results.
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 future
financial results. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in
spot coal prices.
The market price of soda ash and energy costs directly affects the profitability of Ciner Wyoming’s operations. If the market
price for soda ash declines, Ciner Wyoming’s sales revenues will decrease. Historically, the global market and, to a lesser extent,
the domestic market for soda ash have been volatile and are likely to remain volatile in the future.
Interest Rate Risk
Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to
variable interest rates based upon LIBOR. At December 31, 2019 we did not have any borrowings outstanding under the Opco
Credit Facility.
Fair Value of Financial Assets and Liabilities
Our financial assets and liabilities consist of cash and cash equivalents, restricted cash, contract receivable and debt. The
carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair
value due to their short-term nature. We use available market data and valuation methodologies to estimate the fair value of our
debt and contract receivable.
The following table shows the carrying amount and estimated fair value of our debt and contract receivable:
(In thousands)
Debt:
NRP 2025 Senior Notes
NRP 2022 Senior Notes
Opco Senior Notes
Opco Credit Facility
Assets:
Contract receivable (current and long-term)
December 31,
2019
2018
Fair Value
Hierarchy Level
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
$
$
294,084
—
222,114
—
269,250
—
201,090
—
$
— $
334,024
338,734
—
—
356,871
352,599
—
$
38,945
$
33,460
$
40,776
$
34,704
1
1
3
3
3
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm
Report of Deloitte & Touche, LLP, Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2019 and 2018
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2019, 2018 and 2017
Consolidated Statements of Partners’ Capital for the years ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
Page
61
62
63
64
65
66
68
60
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Partners of Natural Resource Partners L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. (the Partnership) as of December
31, 2019 and 2018, the related consolidated statements of comprehensive income (loss), partners’ capital, and cash flows for each
of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated
financial statements”). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements
present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of
its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S.
generally accepted accounting principles.
We did not audit the financial statements of Ciner Wyoming LLC (Ciner Wyoming), a limited liability company in which the
Partnership has a 49% interest. In the consolidated financial statements, the Partnership’s investment in Ciner Wyoming is stated
at $263 million and $247 million as of December 31, 2019 and 2018, respectively, and the Partnership’s equity in the net income
of Ciner Wyoming is stated at $47 million in 2019, $48 million in 2018 and $40 million in 2017. Those statements were audited
by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ciner
Wyoming, is based solely on the report of the other auditors.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Partnership's internal control over financial reporting as of December 31, 2019, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
framework), and our report dated February 27, 2020 expressed an unqualified opinion thereon.
Adoption of ASU No. 2014-09
The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” effective January 1, 2018. As
a result, for the years ended December 31, 2018 and 2019, the Partnership changed its method for revenue recognition related to
royalty lease arrangements.
Basis for Opinion
These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on
the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error
or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether
due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2002.
Houston, Texas
February 27, 2020
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ciner Wyoming LLC (“the Company”) as of December 31, 2019 and 2018,
and the related statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years
in the period ended December 31, 2019, and the related notes included in Exhibit 99.1 (collectively referred to as the "financial
statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company
as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period
ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required
to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are
required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion
on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due
to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2020
We have served as the Company’s auditor since 2008.
62
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash
Accounts receivable, net
Prepaid expenses and other, net
Current assets of discontinued operations
Total current assets
Land
Mineral rights, net
Intangible assets, net
Equity in unconsolidated investment
Long-term contract receivable
Other assets, net
Total assets
LIABILITIES AND CAPITAL
Current liabilities
Accounts payable
Accrued liabilities
Accrued interest
Current portion of deferred revenue
Current portion of long-term debt, net
Current liabilities of discontinued operations
Total current liabilities
Deferred revenue
Long-term debt, net
Other non-current liabilities
Total liabilities
Commitments and contingencies (see Note 16)
Class A Convertible Preferred Units (250,000 units issued and outstanding at $1,000 par
value per unit; liquidation preference of $1,500 per unit)
Partners’ capital
Common unitholders’ interest (12,261,199 and 12,249,469 units issued and outstanding
at December 31, 2019 and 2018, respectively)
General partner’s interest
Warrant holders’ interest
Accumulated other comprehensive loss
Total partners’ capital
Non-controlling interest
Total capital
Total liabilities and capital
December 31,
2019
2018
98,265
—
30,869
1,244
1,706
132,084
24,008
605,096
17,687
263,080
36,963
6,989
1,085,907
1,179
8,764
2,316
4,608
45,776
65
62,708
47,213
470,422
4,949
585,292
$
$
$
$
$
$
101,839
104,191
32,058
3,462
993
242,543
24,008
743,112
42,513
247,051
38,945
3,475
1,341,647
2,414
12,347
14,345
3,509
115,184
947
148,746
49,044
557,574
1,150
756,514
164,587
$
164,587
271,471
3,270
66,816
(2,594)
338,963
(2,935)
336,028
1,085,907
$
$
$
$
355,113
5,014
66,816
(3,462)
423,481
(2,935)
420,546
1,341,647
$
$
$
$
$
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
63
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands, except per unit data)
Revenues and other income
Coal royalty and other
Transportation and processing services
Equity in earnings of Ciner Wyoming
Gain on litigation settlement
Gain on asset sales and disposals
Total revenues and other income
Operating expenses
Operating and maintenance expenses
Depreciation, depletion and amortization
General and administrative expenses
Asset impairments
Total operating expenses
Income from operations
Other expenses, net
Interest expense, net
Debt modification expense
Loss on extinguishment of debt
Total other expenses, net
Net income (loss) from continuing operations
Income from discontinued operations (see Note 4)
Net income (loss)
Net income attributable to non-controlling interest
Net income (loss) attributable to NRP
Less: income attributable to preferred unitholders
Net income (loss) attributable to common unitholders and general
partner
Net income (loss) attributable to common unitholders
Net income (loss) attributable to the general partner
Income (loss) from continuing operations per common unit (see
Note 7)
Basic
Diluted
Net income (loss) per common unit (see Note 7)
Basic
Diluted
Net income (loss)
Comprehensive income (loss) from unconsolidated investment and
other
Comprehensive income (loss)
Comprehensive income attributable to non-controlling interest
Comprehensive income (loss) attributable to NRP
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
For the Years Ended December 31,
2019
2018
2017
191,069
19,279
47,089
—
6,498
263,935
32,738
14,932
16,730
148,214
212,614
51,321
$
$
$
$
$
(47,453) $
—
(29,282)
(76,735) $
(25,414) $
956
(24,458) $
—
(24,458) $
(30,000)
178,878
23,887
48,306
25,000
2,441
278,512
29,509
21,689
16,496
18,280
85,974
192,538
$
$
$
$
$
(70,178) $
—
—
(70,178) $
122,360
17,687
140,047
(510)
139,537
(30,000)
$
$
$
$
$
$
$
181,801
20,522
40,457
—
3,545
246,325
24,883
23,414
18,502
2,967
69,766
176,559
(82,028)
(7,939)
(4,107)
(94,074)
82,485
6,182
88,667
—
88,667
(25,453)
63,214
61,950
1,264
4.57
3.68
5.06
3.96
(54,458) $
109,537
(53,369) $
(1,089)
107,346
2,191
(4.43) $
(4.43)
(4.35) $
(4.35)
7.35
5.90
8.77
6.76
(24,458) $
140,047
$
88,667
868
(23,590) $
—
(23,590) $
(149)
139,898
(510)
139,388
$
$
(1,647)
87,020
—
87,020
The accompanying notes are an integral part of these consolidated financial statements.
64
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Balance at December 31, 2016
Net income (1)
Distributions to common
unitholders and general partner
Distributions to preferred
unitholders
Issuance of warrants
Comprehensive loss from
unconsolidated investment and
other
Common Unitholders
Units
Amounts
General
Partner
Warrant
Holders
Accumulated
Other
Comprehensive
Loss
Partners'
Capital
Excluding
Non-
Controlling
Interest
Non-
Controlling
Interest
Total
Capital
12,232
—
$152,309
86,894
$
887
1,773
$
— $
—
(1,666) $ 151,530
88,667
—
$
(3,394) $ 148,136
88,667
—
— (22,018)
(449)
— (17,334)
(354)
—
—
— 66,816
—
—
—
—
—
—
—
(22,467)
— (22,467)
(17,688)
66,816
— (17,688)
—
66,816
—
—
(1,647)
(1,647)
—
(1,647)
Balance at December 31, 2017
12,232
$199,851
$ 1,857
$ 66,816
$
(3,313) $ 265,211
$
(3,394) $ 261,817
Cumulative effect of adoption
of accounting standard
Net income (2)
Distributions to common
unitholders and general partner
Distributions to preferred
unitholders
Issuance of unit-based awards
Unit-based awards amortization
and vesting
Comprehensive income (loss)
from unconsolidated investment
and other
—
69,057
— 136,746
1,409
2,791
— (22,036)
(450)
— (29,660)
(605)
17
—
—
546
560
49
—
—
12
—
—
—
—
—
—
—
—
—
—
—
—
—
70,466
139,537
—
510
70,466
140,047
(22,486)
— (22,486)
(30,265)
— (30,265)
546
560
—
—
546
560
(149)
(88)
(51)
(139)
Balance at December 31, 2018
12,249
$355,113
$ 5,014
$ 66,816
$
(3,462) $ 423,481
$
(2,935) $ 420,546
Net loss (2)
Distributions to common
unitholders and general partner
Distributions to preferred
unitholders
Issuance of unit-based awards
Unit-based awards amortization
and vesting
Comprehensive income (loss)
from unconsolidated investment
and other
— (23,969)
(489)
— (32,487)
(663)
— (29,400)
486
12
—
—
1,804
(76)
(600)
—
—
8
—
—
—
—
—
—
—
—
—
—
—
(30,000)
486
1,804
868
800
(24,458)
— (24,458)
(33,150)
— (33,150)
— (30,000)
—
—
—
486
1,804
800
Balance at December 31, 2019
12,261
$271,471
$ 3,270
$ 66,816
$
(2,594) $ 338,963
$
(2,935) $ 336,028
(1) Net income includes $25.5 million attributable to preferred unitholders that accumulated during the period, of which $24.9
million is allocated to the common unitholders and $0.5 million is allocated to the general partner.
(2) Net income (loss) includes $30.0 million attributable to preferred unitholders that accumulated during the period, of which
$29.4 million is allocated to the common unitholders and $0.6 million is allocated to the general partner.
The accompanying notes are an integral part of these consolidated financial statements.
65
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
2019
2018
2017
$
(24,458) $
140,047
$
88,667
14,932
31,850
(47,089)
(6,498)
—
29,282
(956)
148,214
7,462
2,361
3,687
(6,035)
(1,234)
(3,656)
(12,029)
(732)
2,218
137,319
(8)
137,311
$
$
— $
6,500
1,743
(22)
21,689
44,453
(48,306)
(2,441)
—
—
(17,687)
18,280
(62)
1,434
7,133
(6,062)
1,138
19
(1,138)
19,465
320
178,282
10,641
188,923
2,097
2,449
3,061
—
$
$
$
8,221
$
7,607
$
(629)
7,592
$
183,021
190,628
$
23,414
43,354
(40,457)
(3,545)
7,939
4,107
(6,182)
2,967
2,353
18
10,284
3,919
(184)
(7,963)
(105)
(15,957)
(478)
112,151
14,988
127,139
5,646
1,151
3,010
—
9,807
(6,264)
3,543
(In thousands)
Cash flows from operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities of continuing operations:
Depreciation, depletion and amortization
Distributions from unconsolidated investment
Equity earnings from unconsolidated investment
Gain on asset sales and disposals
Debt modification expense
Loss on extinguishment of debt
Income from discontinued operations
Asset impairments
Bad debt expense
Unit-based compensation expense
Amortization of debt issuance costs and other
Change in operating assets and liabilities:
Accounts receivable
Accounts payable
Accrued liabilities
Accrued interest
Deferred revenue
Other items, net
Net cash provided by operating activities of continuing operations
Net cash provided by (used in) operating activities of discontinued
operations
Net cash provided by operating activities
Cash flows from investing activities
Distributions from unconsolidated investment in excess of cumulative
earnings
Proceeds from asset sales and disposals
Return of long-term contract receivables
Acquisition of mineral rights
Net cash provided by investing activities of continuing operations
Net cash provided by (used in) investing activities of discontinued
operations
Net cash provided by investing activities
$
$
$
$
$
66
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from financing activities
Proceeds from issuance of preferred units and warrants, net
Debt borrowings
Debt repayments
Redemption of preferred units paid-in-kind
Distributions to common unitholders and general partner
Distributions to preferred unitholders
Contributions from (to) discontinued operations
Debt issuance costs and other
Net cash used in financing activities of continuing operations
Net cash provided by (used in) financing activities of discontinued
operations
Net cash used in financing activities
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash of continuing operations at
beginning of period
Cash and cash equivalents of discontinued operations at beginning of period
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Less: cash and cash equivalents of discontinued operations at end of period
Cash, cash equivalents and restricted cash of continuing operations at end of
period
Supplemental cash flow information:
Cash paid during the period for interest of continuing operations
Non-cash investing and financing activities:
Issuance of 2022 Senior Notes in exchange for 2018 Senior Notes
$
$
$
$
$
$
$
$
$
$
Years Ended December 31,
2019
2018
2017
— $
— $
300,000
(463,082)
—
(33,150)
(30,000)
(637)
(26,436)
35,000
(175,706)
(8,844)
(22,486)
(30,265)
195,690
(228)
(253,305) $
(6,839) $
637
(252,668) $
(107,765) $
(196,509)
(203,348) $
176,203
$
$
$
$
206,030
—
206,030
98,265
—
$
$
$
26,980
2,847
29,827
206,030
—
242,100
180,688
(492,319)
—
(22,467)
(8,844)
5,784
(39,091)
(134,149)
(7,077)
(141,226)
(10,544)
39,171
1,200
40,371
29,827
(2,847)
98,265
$
206,030
$
26,980
58,597
$
64,991
$
72,850
— $
— $
240,638
The accompanying notes are an integral part of these consolidated financial statements.
67
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general
partner of the Partnership is NRP (GP) LP ("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural
Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning,
managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal and other natural
resources and owns a non-controlling 49% interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining and soda ash
production business. The Partnership is organized into two operating segments further described in Note 8. Segment Information.
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.
The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership
owns its subsidiaries through one wholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole
responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership,
its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers
of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability
company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC.
Subject to the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with
The Blackstone Group Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP
(collectively referred to as "GoldenTree"), RCM is entitled to appoint the directors of the Board of Directors of GP Natural Resource
Partners LLC (the "Board of Directors"). RCM has delegated the right to appoint one director to Blackstone.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally
accepted accounting principles in the United States of America ("GAAP"). The Consolidated Financial Statements include the
accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with
International Paper Company controlled by the Partnership. The Partnership has an equity investment in Ciner Wyoming through
which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the
investee’s activities and is accounted for using the equity method. Intercompany transactions and balances have been eliminated.
Certain reclassifications have been made to prior year amounts on the Consolidated Balance Sheets, Consolidated Statements of
Comprehensive Income (Loss) and Consolidated Statements of Cash Flows to conform with current year presentation. These
reclassifications had no impact on previously reported total assets, total liabilities, partners' capital, net income (loss) or cash flows
from operating, investing or financing activities.
Use of Estimates
Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities on the accompanying Consolidated Balance Sheets, the
disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and
expenses on the accompanying Consolidated Statements of Comprehensive Income (Loss) during the reporting period. Actual
results could differ from those estimates. The most significant estimates pertain to coal and aggregates reserves and related cash
flow estimates which are used to compute depreciation, depletion and amortization and impairments of coal and aggregates
properties and related intangible assets and commitments and contingencies.
Fair Value
The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is
defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date. See Note 13. Fair Value Measurements for further details.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
There are three levels of inputs that may be used to measure fair value:
• Level 1—Quoted prices in active markets for identical assets or liabilities.
• Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices
in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for
substantially the full term of the assets or liabilities.
• Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value
of the assets or liabilities. Level 3 assets and liabilities include financial assets and liabilities whose value is determined
using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the
determination of fair value requires significant management judgment or estimation.
Cash, Cash Equivalents and Restricted Cash
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be
cash equivalents. Restricted cash at December 31, 2018 included cash proceeds received from the sale of the Partnership's
construction aggregates business that the Partnership used to repay debt in 2019.
Allowance for Doubtful Accounts
The Partnership records an allowance for doubtful accounts for its accounts receivables and notes receivables which it
determines to be uncollectible based on the specific identification method. Receivables are written off when collection efforts are
exhausted and future recovery is doubtful. The allowance for doubtful accounts receivable is included in accounts receivable, net
and the allowance for doubtful accounts for notes receivable is included in prepaid expenses and other, net on the Partnership's
Consolidated Balance Sheets, respectively. The allowance for doubtful accounts related to accounts receivables was $0.4 million
at December 31, 2019. The allowance for doubtful accounts related to notes receivables was $1.2 million at December 31, 2019
and 2018. The Partnership recorded bad debt expense of $7.5 million, $(0.1) million and $2.4 million included in operating and
maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2019,
2018 and 2017, respectively.
Mineral Rights
Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the
assets acquired. Coal and aggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined
in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.
Intangible Assets
The Partnership’s intangible assets consist of mineral royalty and transportation contracts that at acquisition were more
favorable for the Partnership than prevailing market rates, known as above-market contracts. The estimated fair value of the above-
market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets
acquired. Intangible assets are amortized on a unit-of-production basis by asset based upon minerals mined or transported in relation
to the net book value of the intangible asset and estimated proven and probable tonnage expected to be mined or transported during
the above-market contract term.
Asset Impairment
The Partnership has developed procedures to evaluate its long-lived assets for possible impairment periodically or whenever
events or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances
include, but are not limited to, specific events such as a reduction in economically recoverable reserves or production ceasing on
a property for an extended period. This analysis is based on historic, current and future performance and 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 is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usually
determined based upon the present value of the projected future cash flows compared to the asset's net book value. The Partnership
believes its estimates of cash flows and discount rates are consistent with those of principal market participants.
69
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership evaluates its equity investment for impairment when events or changes in circumstances indicate, in
management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in
value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying
value of the investment to determine whether potential impairment has occurred. If the estimated fair value is less than the carrying
value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated
fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on
quoted market prices (Level 1), or upon the present value of expected cash flows using discount rates believed to be consistent
with those used by principal market participants (Level 3), plus market analysis of comparable assets owned by the investee, if
appropriate (Level 3).
Accrued Liabilities
Included in accrued liabilities on the Partnership's Consolidated Balance Sheets at December 31, 2019 were $3.7 million of
accrued employee costs and $5.0 million of other accrued liabilities, which includes property and franchise taxes and disputed
well liabilities.
Revenue Recognition
Coal Royalty and Other Segment Revenues
Royalty-based leases. Approximately two-thirds of the Partnership's royalty-based leases have initial terms of five to 40
years, with substantially all lessees having the option to extend the lease for additional terms. For these types of leases, the lessees
generally make payments to NRP based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral
mined and sold. Most of NRP’s coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts,
either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that
generally range from three to five years.
In accordance with previous accounting standards in effect prior to January 1, 2018, the Partnership recognized all coal and
aggregates royalty revenues over the lease term based on production. The recognition of revenue from minimum payments was
deferred until either recoupment through royalty production occurred or when the recoupment period expired for unrecouped
minimums. In accordance with the accounting standard in effect subsequent to January 1, 2018 ("ASC 606"), management has
defined NRP's coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell NRP's
coal or aggregates over the lease term. The Partnership then evaluated the likelihood that consideration NRP expected to receive
from its lessees resulting from production would exceed consideration expected to be received from minimum payments over the
lease term.
As a result of this evaluation, revenue recognition from the Partnership's royalty-based leases is based on either production
or minimum payments as follows:
• Production Leases: Leases for which the Partnership expects that consideration from production will be greater than
consideration from minimums over the lease term. Revenue recognition for these leases is recognized over time based
on production as coal royalty revenues or aggregates royalty revenues, as applicable. Deferred revenue from minimums
is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the
recoupment period expires. In addition, NRP recognizes breakage revenue from minimums when NRP determines that
recoupment is remote. This breakage revenue is included in production lease minimum revenues.
• Minimum Leases: Leases for which the Partnership expects that consideration from minimums will be greater than
consideration from production over the lease term. Revenue recognition for these leases is recognized straight-line over
the lease term based on the minimum consideration amount as minimum lease straight-line revenues.
This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease.
Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of
volume of hydrocarbons sold by lessees and the corresponding revenues from those sales. Also, included within oil and gas royalty
revenues are lease bonus payments, which are generally paid upon the execution of a lease. The Partnership also has overriding
royalty revenue interests in coal reserves. Revenues from these interests are recognized over time based on when the coal is sold.
70
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property owned by the
Partnership that is recognized over time as transportation across the property occurs.
Other revenues. Other revenues consists primarily of rental payments and surface damage fees related to certain land owned
by the Partnership and is recognized straight-line over time as it is earned. Other revenues also include property tax revenues. The
majority of property taxes paid on the Partnership's properties are reimbursable by the lessee and are recognized on a gross basis
over time which reflects the reimbursement of property taxes by the lessee. Property taxes paid by NRP are included in operating
and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
Transportation and processing services revenues. The Partnership owns transportation and processing infrastructure that is
leased to third parties for throughput fees. Revenue is recognized over time based on the coal tons transported over the beltlines
or processed through the facilities.
Contract Modifications
Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A
majority of the Partnership's contract modifications pertain to its coal and aggregates royalty contracts and include, but are not
limited to, extending the lease term, changes to royalty rates, floor prices or minimum consideration, assignment of the contract
or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred
and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and
related forfeited minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications
are recognized in lease amendment revenues within coal royalty and other revenues on the Consolidated Statements of
Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognized prospectively in accordance
with the above lease classification.
Contract Assets and Liabilities from Contracts with Customers
Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes
unconditional. Receivables are recognized when the minimums are contractually owed, production occurs or minimums accrued
for based on the passage of time.
Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time.
The current portion of deferred revenue relates to deferred revenue on minimum leases and lease amendment fees that are to be
recognized as revenue on a straight-line basis over the next twelve months. The long-term portion of deferred revenue relates to
deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-line basis
beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as coal
royalty revenues from its production leases over the next twelve months, the Partnership is unable to estimate the current portion
of deferred revenue.
Equity in Earnings of Ciner Wyoming
The Partnership accounts for non-marketable equity investments using the equity method of accounting if the investment
gives it the ability to exercise significant influence over, but not control of, an investee. The Partnership's 49% investment in Ciner
Wyoming is accounted for using this method. Under the equity method of accounting, investments are stated at initial cost and are
adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis
difference between the investment and the proportional share of investee's net assets is attributed to net tangible assets and is
amortized over its estimated useful life. The carrying value in Ciner Wyoming is recognized in equity in unconsolidated investment
on the Partnership's Consolidated Balance Sheets. The Partnership's adjusted share of the earnings or losses of Ciner Wyoming
and amortization of the basis difference is recognized in equity in earnings of Ciner Wyoming on the Consolidated Statements of
Comprehensive Income (Loss). The Partnership decreases its investment for its proportional share of distributions received from
Ciner Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions
received are considered returns on investment and classified as operating cash inflows unless the cumulative distributions received
exceed the Partnership's cumulative equity in earnings. The excess of cumulative distributions received over the Partnership's
cumulative equity in earnings are considered returns of investment and classified as investing cash inflows.
71
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Property Taxes
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually
responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of
property taxes is included in operating and maintenance expenses and in coal royalty and other revenues, respectively, on the
Consolidated Statements of Comprehensive Income (Loss).
Transportation Revenues and Expenses
The Partnership records transportation and processing revenues and pays transportation and processing costs to an affiliate
of Foresight Energy LP to operate equipment on behalf of the Partnership. The revenues and expenses related to these transactions
are recorded as transportation and processing services revenues and operating and maintenance expenses, respectively, on the
Consolidated Statements of Comprehensive Income (Loss). See Note 14. Related Party Transactions for more information.
Unit-Based Compensation
The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units. Compensation
cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards
based on the fair value of an award and is recognized over the service period, which is generally the vesting period. Forfeitures
are recognized as they occur. Unit-based compensation expense for all awards is recognized in general and administrative expenses
and operating and maintenance expenses on the Consolidated Statements of Comprehensive Income (Loss). See Note 17. Unit-
Based Compensation for more information.
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s debt. These costs are
amortized over the term of the respective line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's
revolving credit facility are included in other assets, net on the Partnership's Consolidated Balance Sheets. Deferred financing
costs related to the Partnership's note agreements are included as a direct deduction from the carrying amount of the debt liability
in current portion of long-term debt, net or long-term debt, net on the Partnership's Consolidated Balance Sheets.
Income Taxes
The Partnership is not subject to federal or material state income taxes as the unitholders are taxed individually on their
allocable share of taxable income. Net income (loss) for financial statement purposes may differ significantly from taxable income
reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities. In
the event of an examination of the Partnership’s tax return, the tax liability of the unitholders could be changed if an adjustment
in the Partnership’s income is ultimately sustained by the taxing authorities.
Recently Adopted Accounting Standards
Leases
On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments
(the “new lease standard” and "ASC 842") and recognized assets and liabilities on its Consolidated Balance Sheet for the present
value of the rights and obligations created by all leases with terms of more than 12 months. This standard does not apply to leases
that explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore
for those natural resources and rights to use the land in which those natural resources are contained. The guidance also required
disclosures designed to give financial statement users information on the amount, timing and uncertainty of cash flows arising
from leases. The guidance was adopted by NRP on January 1, 2019 using a modified retrospective approach.
The Partnership is a lessee in one lease that is accounted for as an operating lease under the new lease standard, and the
adoption of the new lease standard did not have a material impact to the Partnership's Consolidated Financial Statements. For lease
agreements entered into or reassessed after the adoption of ASC 842, the Partnership elected to not combine lease and non-lease
components. See Note 19. Leases for more information.
72
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Recently Issued Accounting Standards
Credit Losses
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326). The new standard
changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at
fair value through net income. The new standard replaces today's "incurred loss" model with an "expected credit loss" model that
requires entities to estimate an expected lifetime credit loss on financial assets, including trade accounts receivable. The guidance
is effective for annual and interim periods beginning after December 15, 2019 and is to be adopted using a modified retrospective
approach. As a result of implementation of the new standard the Partnership expects to record an approximate $5 million reduction
of its financial assets and a corresponding decrease in Partners' Capital on January 1, 2020. NRP does not expect this standard to
have a material effect on its Consolidated Financial Statements subsequent to adoption.
3. Revenues from Contracts with Customers
The following table represents the Partnership's Coal Royalty and Other segment revenues by major source:
(In thousands)
Coal royalty revenues
Production lease minimum revenues
Minimum lease straight-line revenues
Property tax revenues
Wheelage revenues
Coal overriding royalty revenues
Lease amendment revenues
Aggregates royalty revenues
Oil and gas royalty revenues
Other revenues
Year Ended December 31,
2019
2018
$
109,612
$
129,341
24,068
14,910
6,287
5,880
13,496
7,991
4,265
3,031
1,529
8,207
2,362
5,422
6,484
13,878
—
4,739
6,608
1,837
178,878
23,887
202,765
Coal royalty and other revenues (1)
Transportation and processing services revenues (2)
Total Coal royalty and Other segment revenues
$
$
191,069
19,279
210,348
$
$
(1) Coal royalty and other revenues from contracts with customers as defined under ASC 606.
(2) Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $9.6 million
and $13.2 million for the year ended December 31, 2019 and 2018, respectively. The remaining transportation and processing
services revenues of $9.7 million and $10.7 million for the year ended December 31, 2019 and 2018, respectively, related
to other NRP-owned infrastructure leased to and operated by third-party operators accounted for under other guidance. See
Note 18. Financing Transaction and Note 19. Leases for more information.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table details the Partnership's Coal Royalty and Other segment receivables and liabilities resulting from
contracts with customers:
(In thousands)
Receivables
Accounts receivable, net
Prepaid expenses and other (1)
Contract liabilities
Current portion of deferred revenue
Deferred revenue
December 31,
2019
2018
$
$
27,915
$
90
4,608
$
47,213
29,001
2,483
3,509
49,044
(1) Prepaid expenses and other includes notes receivable from contracts with customers.
The following table shows the activity related to the Partnership's Coal Royalty and Other segment deferred revenue:
(In thousands)
Balance at end of prior period (current and non-current)
Cumulative adjustment for change in accounting principle
Balance at beginning of period (current and non-current)
Increase due to minimums and lease amendment fees
Recognition of previously deferred revenue
Balance at end of period (current and non-current)
Year Ended December 31,
2019
2018
52,553
—
52,553
47,038
(47,770)
51,821
$
$
$
100,605
(65,591)
35,014
37,781
(20,242)
52,553
$
$
$
The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty
and overriding royalty leases are as follows (in thousands):
Lease Term (1)
0 - 5 years
5 - 10 years
10+ years
Total
Weighted Average
Remaining Years as of
December 31, 2019
Annual Minimum
Payments (2)
2.3
6.2
11.9
9.1
$
$
13,812
9,718
44,757
68,287
(1) Lease term does not include renewal periods.
(2) Annual minimum payments do not include $5.0 million from a coal infrastructure lease that is accounted for as a financing
transaction. See Note 18. Financing Transaction for additional information.
4. Discontinued Operations
In December 2018, the Partnership sold VantaCore Partners LLC, its construction aggregates materials business for $205
million, before customary purchase price adjustments and transaction expenses, and recorded a gain of $13.1 million, and in July
2016, the Partnership sold its non-operated oil and gas working interest assets. The Partnership's exit from both its construction
aggregates business and non-operated oil and gas working interest business represented strategic shifts to reduce debt and focus
on its Coal Royalty and Other and Soda Ash business segments. As a result, the Partnership classified the assets and liabilities,
operating results and cash flows of these businesses as discontinued operations on its Consolidated Balance Sheets, Consolidated
Statements of Comprehensive Income (Loss) and Consolidated Statements of Cash Flows for all periods presented.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations on
the Consolidated Balance Sheets:
(In thousands)
Current assets
ASSETS
Accounts receivable, net
Total assets of discontinued
operations
LIABILITIES
Current liabilities
Accounts payable
Accrued liabilities
Total liabilities of discontinued
operations
December 31,
2019
2018
Construction
Aggregates
NRP
Oil and Gas
Total
Construction
Aggregates
NRP
Oil and Gas
Total
$
$
$
$
— $
1,706
— $
1,706
$
$
1,706
1,706
$
42
23
— $
—
42
23
$
$
$
$
$
$
5
5
181
766
988
988
$
$
— $
—
65
$
— $
65
$
947
$
— $
993
993
181
766
947
The following tables present summarized financial results of the Partnership's discontinued operations on the Consolidated
Statements of Comprehensive Income (Loss):
(In thousands)
Revenues and other income
Oil and gas
Gain on asset sales and disposals
Total revenues and other income
Operating expenses
Operating and maintenance expenses
Total operating expenses
Other income
Income from discontinued operations
For the Year Ended December 31, 2019
Construction
Aggregates
NRP
Oil and Gas
Total
$
$
$
$
$
$
— $
280
280
27
27
$
$
$
— $
253
$
2
—
2
16
16
717
703
$
$
$
$
$
$
2
280
282
43
43
717
956
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(In thousands)
Revenues and other income
Construction aggregates
Road construction and asphalt paving services
Oil and gas
Gain on asset sales and disposals
Total revenues and other income
Operating expenses
Operating and maintenance expenses
Depreciation, depletion and amortization
Asset impairments
Total operating expenses
Interest expense
Income (loss) from discontinued operations
(In thousands)
Revenues and other income
Construction aggregates
Road construction and asphalt paving services
Oil and gas
Gain (loss) on asset sales and disposals
Total revenues and other income
Operating expenses
Operating and maintenance expenses
Depreciation, depletion and amortization
Asset impairments
Total operating expenses
Interest expense
Income (loss) from discontinued operations
For the Year Ended December 31, 2018
Construction
Aggregates
NRP
Oil and Gas
Total
116,066
$
18,400
—
13,414
147,880
$
— $
—
(3)
—
(3) $
117,568
$
134
$
12,218
232
—
—
116,066
18,400
(3)
13,414
147,877
117,702
12,218
232
130,018
$
134
$
130,152
(38) $
$
17,824
— $
(137) $
(38)
17,687
For the Year Ended December 31, 2017
Construction
Aggregates
NRP
Oil and Gas
Total
112,970
$
18,411
—
311
131,692
$
— $
—
38
(289)
(251) $
111,633
$
290
$
12,579
64
124,276
$
(693) $
$
6,723
—
—
290
$
— $
(541) $
112,970
18,411
38
22
131,441
111,923
12,579
64
124,566
(693)
6,182
$
$
$
$
$
$
$
$
$
$
$
$
Capital expenditures related to the Partnership's discontinued operations were $10.9 million and $7.6 million during the years
ended December 31, 2018 and 2017, respectively, of which $0.9 million and $0.3 million were funded with accounts payable or
accrued liabilities during 2018 and 2017, respectively.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
5. Class A Convertible Preferred Units and Warrants
On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in
NRP (the "preferred units") to certain entities controlled by funds affiliated with The Blackstone Group Inc. (collectively referred
to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree") (together
the "preferred purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000 preferred units to
the preferred purchasers at a price of $1,000 per preferred unit (the "per unit purchase price"), less a 2.5% structuring and origination
fee. The preferred units entitle the preferred purchasers to receive cumulative distributions at a rate of 12% of the purchase price
per year, up to one half of which NRP may pay in additional preferred units (such additional preferred units, the "PIK units"). The
preferred units have a perpetual term, unless converted or redeemed as described below.
NRP also issued two tranches of warrants (the "warrants") to purchase common units to the preferred purchasers (warrants
to purchase 1.75 million common units with a strike price of $22.81 and warrants to purchase 2.25 million common units with a
strike price of $34.00). The warrants may be exercised by the holders thereof at any time before the eighth anniversary of the
closing date. Upon exercise of the warrants, NRP may, at its option, elect to settle the warrants in common units or cash, each on
a net basis.
After March 2, 2022 and prior to March 2, 2025, the holders of the preferred units may elect to convert up to 33% of the
outstanding preferred units in any 12-month period into common units if the volume weighted average trading price of our common
units (the "VWAP") for the 30 trading days immediately prior to date notice is provided is greater than $51.00. In such case, the
number of common units to be issued upon conversion would be equal to the per unit purchase price plus the value of any accrued
and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior
to the notice of conversion. Rather than have the preferred units convert to common units in accordance with the provisions of
this paragraph, NRP would have the option to elect to redeem the preferred units proposed to be converted for cash at a price equal
to the per unit purchase price plus the value of any accrued and unpaid distributions.
On or after March 2, 2025, the holders of the preferred units may elect to convert the preferred units to common units at a
conversion rate equal to the Liquidation Value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days
immediately prior to the notice of conversion. The “liquidation value” will be an amount equal to the greater of: (1) (a) the per
unit purchase price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021, 1.70
and (iii) on or after March 2, 2021, 1.85, less (b)(i) all preferred unit distributions previously made by NRP and (ii) all cash payments
previously made in respect of redemption of any PIK units; and (2) the per unit purchase price plus the value of all accrued and
unpaid distributions.
To the extent the holders of the preferred units have not elected to convert their preferred units before March 2, 2029, NRP
has the right to force conversion of the preferred units at a price equal to the liquidation value divided by an amount equal to a
10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion.
In addition, NRP has the ability to redeem at any time (subject to compliance with its debt agreements) all or any portion of
the preferred units and any outstanding PIK units for cash. The redemption price for each outstanding PIK unit is $1,000 plus the
value of any accrued and unpaid distributions per PIK unit. The redemption price for each preferred unit is the liquidation value
divided by the number of outstanding preferred units. The preferred units are redeemable at the option of the preferred purchasers
only upon a change in control.
The terms of the preferred units contain certain restrictions on NRP's ability to pay distributions on its common units. To the
extent that either (i) NRP's consolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership
Agreement dated March 2, 2017 (the "restated partnership agreement"), is greater than 3.25x, or (ii) the ratio of NRP's Distributable
Cash Flow (as defined in the Restated Partnership Agreement) to cash distributions made or proposed to be made is less than 1.2x
(in each case, with respect to the most recently completed four-quarter period), NRP may not increase the quarterly distribution
above $0.45 per quarter without the approval of the holders of a majority of the outstanding preferred units. In addition, if at any
time after January 1, 2022, any PIK units are outstanding, NRP may not make distributions on its common units until it has
redeemed all PIK units for cash.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The holders of the preferred units have the right to vote with holders of NRP’s common units on an as-converted basis and
have other customary approval rights with respect to changes of the terms of the preferred units. In addition, Blackstone has certain
approval rights over certain matters as identified in the restated partnership agreement. GoldenTree also has more limited approval
rights that will expand once Blackstone's ownership goes below the minimum preferred unit threshold (as defined below). These
approval rights are not transferrable without NRP's consent. In addition, the approval rights held by Blackstone and GoldenTree
will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable,
no longer own at least 20% of the total number of preferred units issued on the closing date, together with all PIK units that have
been issued but not redeemed (the "minimum preferred unit threshold").
At the closing, pursuant to the Board Representation and Observation Rights Agreement, the Preferred Purchasers received
certain board appointment and observation rights, and Blackstone appointed one director and one observer to the Board of Directors.
NRP also entered into a registration rights agreement (the "preferred unit and warrant registration rights agreement") with
the preferred purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units
issuable upon exercise of the warrants and to cause such registration statement to become effective not later than 90 days following
the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the preferred units
and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date
or 90 days following the first issuance of any common units upon conversion of preferred units (the "registration deadlines"). In
addition, the preferred unit and warrant registration rights agreement gives the preferred purchasers piggyback registration and
demand underwritten offering rights under certain circumstances. The shelf registration statement to register the common units
issuable upon exercise of the warrants became effective on April 20, 2017. If the shelf registration statement to register the common
units issuable upon conversion of the preferred units is not effective by the applicable registration deadline, NRP will be required
to pay the preferred purchasers liquidated damages in the amounts and upon the term set forth in the preferred unit and warrant
registration rights agreement.
Accounting for the Preferred Units and Warrants
Classification
The preferred units are accounted for as temporary equity on NRP's Consolidated Balance Sheets due to certain contingent
redemption rights that may be exercised at the election of preferred purchasers. The warrants are accounted for as equity on NRP's
Consolidated Balance Sheets.
Initial Measurement
The net transaction price as shown below was allocated to the preferred units and warrants based on their relative fair values
at inception date. NRP allocated the transaction issuance costs to the preferred units and warrants primarily on a pro-rata basis
based on their relative inception date allocated values.
The preferred units and warrants were initially recognized as follows:
(In thousands)
Transaction price, gross
Structuring, origination and other fees to preferred purchasers
Transaction costs to other third parties
Transaction price, net
Allocation of net transaction price
Preferred units, net
Warrant holders interest, net
Transaction price, net
March 2, 2017
250,000
(7,900)
(10,697)
231,403
164,587
66,816
231,403
$
$
$
$
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Subsequent Measurement
Subsequent adjustment of the preferred units will not occur until NRP has determined that the conversion or redemption of
all or a portion of the preferred units is probable of occurring. Once conversion or redemption becomes probable of occurring, the
carrying amount of the preferred units will be accreted to their redemption value over the period from the date the feature is probable
of occurring to the date the preferred units can first be converted or redeemed.
Activity related to the preferred units is as follows:
(In thousands, except unit data)
Balance at December 31, 2016
Issuance of preferred units, net
Distribution paid-in-kind
Balance at December 31, 2017
Redemption of PIK units
Balance at December 31, 2018 and 2019
Units
Outstanding
Financial
Position
— $
250,000
8,844
258,844
(8,844)
250,000
$
$
—
164,587
8,844
173,431
(8,844)
164,587
Subsequent adjustment of the warrants will not occur until the warrants are exercised, at which time, NRP may, at its option,
elect to settle the warrants in common units or cash, each on a net basis. The net basis will be equal to the difference between the
Partnership's common unit price and the strike price of the warrant. Once warrant exercise occurs, the difference between the
carrying amount of the warrants and the net settlement amount will be allocated on a pro-rata basis to the common unitholders
and general partner.
Certain embedded features within the preferred unit and warrant purchase agreement are accounted for at fair value and are
remeasured each quarter. See Note 13. Fair Value Measurements for further information regarding valuation of these embedded
derivatives.
6. Common and Preferred Unit Distributions
The Partnership makes cash distributions to common and preferred unitholders on a quarterly basis, subject to approval by
the Board of Directors. NRP recognizes both common unit and preferred unit distributions on the date the distribution is declared.
Distributions made on the common units and the general partner's general partner ("GP") interest are made on a pro-rata
basis in accordance with their relative percentage interests in the Partnership. The general partner is entitled to receive 2% of such
distributions.
Income (loss) available to common unitholders and the general partner is reduced by preferred unit distributions that
accumulated during the period. NRP reduced net income (loss) available to common unitholders and the general partner by $30.0
million during the years ended December 31, 2019 and 2018 and $25.5 million during the year ended December 31, 2017 as a
result of accumulated preferred unit distributions earned during the period. During the three months ended March 31, 2018, the
Partnership redeemed all of the outstanding PIK units, which resulted in an $8.8 million cash payment during the period. This $8.8
million cash payment is not included in the table below.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows the distributions declared and paid to common and preferred unitholders during the years ended
December 31, 2019, 2018 and 2017, respectively:
Date Paid
Period Covered by Distribution
2019
February 2019
October 1 - December 31, 2018
$
May 2019
May 2019 (2)
August 2019
January 1 - March 31, 2019
Special Distribution
April 1 - June 30, 2019
November 2019
July 1 - September 30, 2019
2018
February 2018
May 2018
August 2018
October 1 - December 31, 2017
$
January 1 - March 31, 2018
April 1 - June 30, 2018
November 2018
July 1 - September 30, 2018
2017
February 2017
May 2017
August 2017
October 1 - December 31, 2016
$
January 1 - March 31, 2017
April 1 - June 30, 2017
November 2017
July 1 - September 30, 2017
Common Units
Preferred Units
Distribution
per Unit
Total
Distribution (1)
(In thousands)
Distribution
per Unit
Total
Distribution
(In thousands)
0.45
0.45
0.85
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
$
5,625
$
30.00
$
5,630
10,635
5,630
5,630
30.00
—
30.00
30.00
$
5,617
$
30.00
$
5,623
5,623
5,623
30.00
30.00
30.00
$
5,615
$
— $
5,619
5,616
5,617
5.00
15.00
15.00
7,500
7,500
—
7,500
7,500
7,765
7,500
7,500
7,500
—
2,500
7,538
7,650
(1) Totals include the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest.
(2) The special distribution of $0.85 per common unit was made to cover the common unitholders’ tax liability resulting from
the sale of NRP’s construction aggregates business in December 2018.
7. Net Income (Loss) Per Common Unit
Basic net income (loss) per common unit is computed by dividing net income (loss), after considering income attributable
to non-controlling interest, preferred unitholders and the general partner’s general partner interest, by the weighted average number
of common units outstanding. Diluted net income (loss) per common unit includes the effect of NRP's preferred units, warrants,
and unvested unit-based awards if the inclusion of these items is dilutive.
The dilutive effect of the preferred units is calculated using the if-converted method. Under the if-converted method, the
preferred units are assumed to be converted at the beginning of the period, and the resulting common units are included in the
denominator of the diluted net income (loss) per unit calculation for the period being presented. Distributions declared in the period
and undeclared distributions on the preferred units that accumulated during the period are added back to the numerator for purposes
of the if-converted calculation. The calculation of diluted net loss per common unit for the year ended December 31, 2019 did not
include the assumed conversion of the preferred units because the impact would have been anti-dilutive. The calculation of diluted
net income (loss) per common unit for the years ended December 31, 2018 and 2017 included the assumed conversion of the
preferred units.
The dilutive effect of the warrants is calculated using the treasury stock method, which assumes that the proceeds from the
exercise of these instruments are used to purchase common units at the average market price for the period. Due to NRP's net loss
during the year ended December 31, 2019, the dilutive effect of the warrants were not included as the impact would have been
anti-dilutive. The calculation of the dilutive effect of the warrants for the years ended December 31, 2018 and 2017 included the
net settlement of warrants to purchase 1.75 million common units with a strike price of $22.81 but did not include the net settlement
of warrants to purchase 2.25 million common units with a strike price of $34.00 because the impact would have been anti-dilutive.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following tables reconcile the numerators and denominators of the basic and diluted net income (loss) per common unit
computations and calculates basic and diluted net income (loss) per common unit:
(In thousands, except per unit data)
Allocation of net income (loss)
Net income (loss) from continuing operations
Less: net income attributable to non-controlling interest
Less: income attributable to preferred unitholders
Net income (loss) from continuing operations attributable to common
unitholders and general partner
Add (less): net loss (income) from continuing operations attributable
to the general partner
Net income (loss) from continuing operations attributable to
common unitholders
Net income from discontinued operations
Less: net income from discontinued operations attributable to the general
partner
Net income from discontinued operations attributable to common
unitholders
Net income (loss)
Less: net income attributable to non-controlling interest
Less: income attributable to preferred unitholders
Net income (loss) attributable to common unitholders and general
partner
Add (less): net loss (income) attributable to the general partner
Net income (loss) attributable to common unitholders
Basic income (loss) per common unit
Weighted average common units—basic
Basic net income (loss) from continuing operations per common unit
Basic net income from discontinued operations per common unit
Basic net income (loss) per common unit
Year Ended December 31,
2019
2018
2017
$
(25,414) $
—
(30,000)
122,360
(510)
(30,000)
$
82,485
—
(25,453)
$
(55,414) $
91,850
$
57,032
1,108
(1,837)
(1,141)
$
$
$
$
$
$
$
$
$
(54,306) $
90,013
956
$
17,687
(19)
(354)
937
$
17,333
(24,458) $
—
(30,000)
(54,458) $
1,089
(53,369) $
140,047
(510)
(30,000)
109,537
(2,191)
107,346
12,260
12,244
(4.43) $
0.08
$
(4.35) $
7.35
1.42
8.77
$
$
$
$
$
$
$
$
$
55,891
6,182
(123)
6,059
88,667
—
(25,453)
63,214
(1,264)
61,950
12,232
4.57
0.50
5.06
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(In thousands, except per unit data)
Diluted income (loss) per common unit
Weighted average common units—basic
Plus: dilutive effect of preferred units
Plus: dilutive effect of warrants
Plus: dilutive effect of unvested unit-based awards
Weighted average common units—diluted
Net income (loss) from continuing operations
Less: net income attributable to non-controlling interest
Less: net income attributable to preferred unitholders
Diluted net income (loss) from continuing operations attributable to
common unitholders and general partner
Add (less): net loss (income) from continuing operations attributable
to the general partner
Diluted net income (loss) from continuing operations attributable
to common unitholders
Diluted net income from discontinued operations attributable to common
unitholders
Net income (loss)
Less: net income attributable to non-controlling interest
Less: net income attributable to preferred unitholders
Diluted net income (loss) attributable to common unitholders and
general partner
Add (less): diluted net loss (income) attributable to the general
partner
Diluted net income (loss) attributable to common unitholders
Diluted net income (loss) from continuing operations per common unit
Diluted net income from discontinued operations per common unit
Diluted net income (loss) per common unit
Year Ended December 31,
2019
2018
2017
12,260
—
—
—
12,244
7,479
511
—
12,232
9,418
300
—
12,260
20,234
21,950
$
(25,414) $
—
(30,000)
122,360
(510)
—
$
82,485
—
—
$
(55,414) $
121,850
$
82,485
1,108
(2,437)
(1,650)
(54,306) $
119,413
$
80,835
937
$
17,333
(24,458) $
—
(30,000)
140,047
(510)
—
$
$
6,059
88,667
—
—
(54,458) $
139,537
$
88,667
1,089
(53,369) $
(2,791)
136,746
(4.43) $
0.08
$
(4.35) $
5.90
0.86
6.76
(1,773)
86,894
3.68
0.28
3.96
$
$
$
$
$
$
$
$
$
$
$
$
82
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
8. Segment Information
The Partnership's segments are strategic business units that offer distinct products and services to different customers in
different geographies within the U.S. and that are managed accordingly. NRP has the following two operating segments:
Coal Royalty and Other—consists primarily of coal royalty properties and coal-related transportation and processing assets.
Other assets include industrial mineral royalty properties, aggregates royalty properties, oil and gas royalty properties and timber.
The Partnership's coal reserves are primarily located in Appalachia, the Illinois Basin and the Northern Powder River Basin in the
United States. The Partnership's industrial minerals and aggregates properties are located in various states across the United States.
The Partnership's oil and gas royalty assets are primarily located in Louisiana and its timber assets are primarily located in West
Virginia.
Soda Ash—consists of the Partnership's 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining operation
and soda ash refinery in the Green River Basin of 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 to the glass and chemicals
industries.
Direct segment costs and certain other costs incurred at the corporate level that are identifiable and that benefit the Partnership's
segments are allocated to the operating segments accordingly. These allocated costs generally include salaries and benefits,
insurance, property taxes, legal, royalty, information technology and shared facilities services and are included in operating and
maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these
departments include interest and financing, corporate headquarters and overhead, centralized treasury, legal and accounting and
other corporate-level activity not specifically allocated to a segment and are included in general and administrative expenses on
the Partnership's Consolidated Statements of Comprehensive Income (Loss).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table summarizes certain financial information for each of the Partnership's business segments:
(In thousands)
For the Year Ended December 31, 2019
Revenues
Gain on asset sales and disposals
Operating and maintenance expenses
Depreciation, depletion and amortization
General and administrative expenses
Asset impairments
Other expenses, net
Net income (loss) from continuing operations
Income from discontinued operations
As of December 31, 2019
Total assets of continuing operations
Total assets of discontinued operations
For the Year Ended December 31, 2018
Revenues
Gain on litigation settlement
Gain on asset sales and disposals
Operating and maintenance expenses
Depreciation, depletion and amortization
General and administrative expenses
Asset impairments
Other expenses, net
Net income (loss) from continuing operations
Income from discontinued operations
As of December 31, 2018
Total assets of continuing operations
Total assets of discontinued operations
For the Year Ended December 31, 2017
Revenues
Gain on asset sales and disposals
Operating and maintenance expenses
Depreciation, depletion and amortization
General and administrative expenses
Asset impairments
Other expenses, net
Net income (loss) from continuing operations
Income from discontinued operations
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$
$ 210,348
6,498
32,489
14,932
—
148,214
—
21,211
—
47,089
—
249
—
—
—
—
46,840
—
$ 817,768
—
$ 263,080
—
$
$ 202,765
25,000
2,441
29,509
21,689
—
18,280
—
160,728
—
48,306
—
—
—
—
—
—
—
48,306
—
$
$
$
— $ 257,437
6,498
—
32,738
—
14,932
—
16,730
16,730
148,214
—
76,735
76,735
(25,414)
(93,465)
956
—
3,353
—
$1,084,201
1,706
— $ 251,071
25,000
—
2,441
—
29,509
—
21,689
—
16,496
16,496
18,280
—
70,178
70,178
(86,674)
122,360
17,687
—
$ 986,680
—
$ 247,051
—
$ 106,923
—
$1,340,654
993
$
$ 202,323
3,545
24,883
23,414
—
2,967
—
154,604
—
40,457
—
—
—
—
—
—
40,457
—
$
— $ 242,780
3,545
—
24,883
—
23,414
—
18,502
18,502
2,967
—
94,074
94,074
(112,576)
82,485
6,182
—
84
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9. Equity Investment
The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Activity related
to this investment is as follows:
(In thousands)
Balance at beginning of period
Income allocation to NRP’s equity interests (1)
Amortization of basis difference
Other comprehensive income (loss)
Distribution
Balance at end of period
For the Year Ended December 31,
2019
2018
2017
$
247,051
$
245,433
$
255,901
52,016
(4,927)
790
(31,850)
263,080
$
53,095
(4,789)
(138)
(46,550)
247,051
$
44,846
(4,389)
(1,925)
(49,000)
245,433
$
(1)
Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $0.6
million, $0.5 million and $0.7 million for the year ended December 31, 2019, 2018 and 2017, 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 $135.8 million and $140.8 million as of December 31, 2019 and 2018, respectively. This
excess basis relates to property, plant 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 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 following table represents summarized financial information for Ciner Wyoming as derived from their respective financial
statements for the years ended December 31, 2019, 2018, and 2017:
(In thousands)
Net sales
Gross profit
Net income
The financial position of Ciner Wyoming is summarized as follows:
(In thousands)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
For the Year Ended December 31,
2019
2018
2017
$
522,843
$
486,759
$
131,712
106,155
104,053
108,357
497,340
114,202
91,523
December 31,
2019
2018
$
170,696
$
282,387
55,339
138,087
138,080
252,743
64,012
109,921
85
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
10. Mineral Rights, Net
The Partnership’s mineral rights consist of the following:
December 31,
2019
2018
(In thousands)
Coal properties
Aggregates properties
Oil and gas royalty properties
Other
Carrying
Value
Accumulated
Depletion
Net Book
Value
Carrying
Value
Accumulated
Depletion
Net Book
Value
$
981,352
41,486
12,395
13,156
$ (420,448) $
(13,357)
(7,887)
(1,601)
560,904
$ 1,164,845
28,129
4,508
11,555
24,920
12,395
13,158
$ (451,210) $
(11,814)
(7,632)
(1,550)
713,635
13,106
4,763
11,608
Total mineral rights, net
$ 1,048,389
$ (443,293) $
605,096
$ 1,215,318
$ (472,206) $
743,112
Depletion expense related to the Partnership’s mineral rights is included in depreciation, depletion and amortization on its
Consolidated Statements of Comprehensive Income (Loss) and totaled $12.1 million, $17.0 million and $20.1 million for the years
ended December 31, 2019, 2018 and 2017, respectively.
Sales of Mineral Rights
During the year ended December 31, 2019, the Partnership recorded a gain of $6.5 million included in gain on asset sales
and disposals on the Consolidated Statements of Comprehensive Income (Loss) primarily related to the disposal of certain coal
mineral rights with a $0 net book value. During the years ended December 31, 2018 and 2017, the Partnership recorded a cumulative
gain of $2.4 million and $3.5 million, respectively, included in gain on asset sales and disposals on the Consolidated Statements
of Comprehensive Income (Loss) related to sales of multiple mineral reserves.
Impairment of Mineral Rights
During the years ended December 31, 2019, 2018 and 2017, 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 included in asset impairments on the Consolidated Statements of Comprehensive Income (Loss) as follows:
(In thousands)
Coal properties (1)
Aggregates and timber royalty properties (2)
Total
For the Year Ended December 31,
2019
2018
2017
$
$
125,806
103
125,909
$
$
5,259
13,021
18,280
$
$
595
2,372
2,967
(1) The Partnership recorded $125.8 million of impairment expense during the year ended December 31, 2019 primarily due to
deterioration in thermal coal markets, lessee capital constraints, thermal coal lease terminations, and expectations of further
reductions in global and domestic thermal coal demand due to low natural gas prices and continued pressure on the electric
power generation industry over emissions and climate change, resulting in reductions in expected cash flows (combination
of lower expected coal sales volumes, sales prices, minimums and/or life of mine assumptions) on certain of our coal properties.
During the year ended December 31, 2019, the Partnership recorded $36.0 million to fully impair certain coal properties. In
addition, NRP recorded $89.8 million of impairment expense on coal royalty properties with $97 million of net book value,
resulting in a fair value of $7.2 million at December 31, 2019. The fair value of the impaired assets at December 31, 2019
was calculated using a discount rate of 15%. The Partnership recorded $5.3 million of coal property impairments during the
year ended December 31, 2018 primarily as a result of lease terminations, of which it recorded $5.0 million of impairment
expense to fully impair certain coal properties during the three months ended December 31, 2018. The Partnership
recorded $0.6 million of coal property impairments during the year ended December 31, 2017. NRP compared the net book
value of its coal properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted
future cash flows, the Partnership recorded an impairment for the excess of the net book value 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 flows from coal sales and minimum payments, discount rate and useful economic life. Estimated cash flows are the
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
(2) The Partnership recorded $0.1 million of aggregates royalty property impairments during the year ended December 31, 2019.
During the three months ended December 31, 2018, the Partnership recorded $13.0 million of impairment expense related
to an aggregates property that the Partnership owns and leases to its former construction aggregates business, which mines,
produces and sells the aggregates. The fair value of the impaired asset was reduced to $2.3 million at December 31, 2018
using a discount rate of 11%. The Partnership recorded $2.4 million of aggregates and timber royalty properties impairments
during the year ended December 31, 2017. NRP compared the net book value of its aggregates and timber properties to
estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted cash flows, the Partnership
recorded an impairment for the excess of the net book value 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 flows from aggregates
and timber sales and minimum payments, 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.
11. Intangible Assets, Net
The Partnership's intangible assets consist of above-market coal royalty and related transportation contracts with subsidiaries
of Foresight Energy pursuant to which the Partnership receives royalty payments for coal sales and throughput fees for the
transportation and processing of coal. The Partnership's intangible assets included on its Consolidated Balance Sheets are as follows:
(In thousands)
Intangible assets at cost
Less: accumulated amortization
Total intangible assets, net
December 31,
2019
2018
$
$
53,878
(36,191)
17,687
$
$
81,109
(38,596)
42,513
Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of
Comprehensive Income (Loss) was $2.5 million, $4.3 million and $3.0 million for the years ended December 31, 2019, 2018 and
2017, respectively.
During the year ended December 31, 2019, the Partnership identified facts and circumstances that indicated that the carrying
value of certain of its above-market contracts exceed future cash flows from those assets and recorded a non-cash impairment
expense of $22.3 million to fully impair these assets. These impairments are included in asset impairments on the Partnership's
Consolidated Statements of Comprehensive Income (Loss) and resulted from deterioration in thermal coal markets, lessee capital
constraints, and expectations of further reductions in global and domestic thermal coal demand due to low natural gas prices and
continued pressure on the electric power generation industry over emissions and climate change, resulting in reductions in expected
cash flows (combination of lower expected coal sales volumes, sales prices and/or life of mine assumptions) on certain of our
intangible assets.
The estimates of amortization expense for the years ended December 31, as indicated below, are based on current mining
plans and are subject to revision as those plans change in future periods.
(In thousands)
2020
2021
2022
2023
2024
87
$
Estimated
Amortization
Expense
508
913
738
765
1,006
Table of Contents
12. Debt, Net
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership's debt consists of the following:
(In thousands)
NRP LP debt:
9.125% senior notes, with semi-annual interest payments in June and December, due
June 2025 issued at par ("2025 Senior Notes")
10.500% senior notes, with semi-annual interest payments in March and September,
due March 2022, $241 million issued at par and $105 million issued at 98.75% ("2022
Senior Notes")
Opco debt:
Revolving credit facility
Senior Notes
8.38% with semi-annual interest payments in March and September, with annual
principal payments in March, due March 2019
5.05% with semi-annual interest payments in January and July, with annual
principal payments in July, due July 2020
5.55% with semi-annual interest payments in June and December, with annual
principal payments in June, due June 2023
4.73% with semi-annual interest payments in June and December, with annual
principal payments in December, due December 2023
5.82% with semi-annual interest payments in March and September, with annual
principal payments in March, due March 2024
8.92% with semi-annual interest payments in March and September, with annual
principal payments in March, due March 2024
5.03% with semi-annual interest payments in June and December, with annual
principal payments in December, due December 2026
5.18% with semi-annual interest payments in June and December, with annual
principal payments in December, due December 2026
Total Opco Senior Notes
Total debt at face value
Net unamortized debt discount
Net unamortized debt issuance costs
Total debt, net
Less: current portion of long-term debt
Total long-term debt, net
NRP LP Debt
2025 Senior Notes
December 31,
2019
2018
$
300,000
$
—
—
345,638
— $
—
— $
21,319
6,780
9,458
24,016
63,423
20,059
79,945
20,375
224,056
524,056
—
(7,858)
516,198
(45,776)
470,422
$
$
$
$
15,290
13,414
37,195
89,529
27,185
107,013
30,555
341,500
687,138
(1,266)
(13,114)
672,758
(115,184)
557,574
$
$
$
$
$
$
In April 2019, NRP and NRP Finance issued the 2025 Senior Notes and used the $300 million proceeds and $76 million of
cash on hand to fund the redemption of the 2022 Senior Notes. The 2025 Senior Notes were issued under an Indenture dated as
of April 29, 2019 (the "2025 Indenture"), bear interest at 9.125% per year and mature on June 30, 2025. Interest is payable semi-
annually on June 30 and December 30 beginning December 30, 2019.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NRP and NRP Finance have the option to redeem the 2025 Senior Notes, in whole or in part, at any time on or after October
30, 2021, at the redemption prices (expressed as percentages of principal amount) of 104.563% for the 12-month period beginning
October 30, 2021, 102.281% for the 12-month period beginning October 30, 2022, and thereafter at 100.000%, together, in each
case, with any accrued and unpaid interest to the date of redemption. Furthermore, before October 30, 2021, NRP may on any one
or more occasions redeem up to 35% of the aggregate principal amount of the 2025 Senior Notes with the net proceeds of certain
public or private equity offerings at a redemption price of 109.125% of the principal amount of 2025 Senior Notes, plus any accrued
and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2025 Senior Notes
issued under the 2025 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180
days of the closing date of such equity offering. In the event of a change of control, as defined in the 2025 Indenture, the holders
of the 2025 Senior Notes may require us to purchase their 2025 Senior Notes at a purchase price equal to 101% of the principal
amount of the 2025 Senior Notes, plus accrued and unpaid interest, if any. The 2025 Senior Notes were issued at par.
The 2025 Senior Notes are the senior unsecured obligations of NRP and NRP Finance. The 2025 Senior Notes rank equal
in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance and senior in right of payment to
any of NRP's subordinated debt. The 2025 Senior Notes are effectively subordinated in right of payment to all future secured debt
of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are structurally subordinated
in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and
each series of Opco’s existing senior notes. None of NRP's subsidiaries guarantee the 2025 Senior Notes. As of December 31,
2019, NRP and NRP Finance were in compliance with the terms of the Indenture relating to their 2025 Senior Notes.
2022 Senior Notes
During the second quarter of 2019, the Partnership redeemed the 2022 Senior Notes at a redemption price equal to 105.250%
of the principal amount of the 2022 Senior Notes, plus accrued and unpaid interest. In connection with the early redemption, the
Partnership paid an $18.1 million call premium and also wrote off $10.4 million of unamortized debt issuance costs and debt
discount. These expenses are included in loss on extinguishment of debt on the Partnership's Consolidated Statements of
Comprehensive Income (Loss). As of December 31, 2018, NRP and NRP Finance were in compliance with the terms of the
Indenture relating to their 2022 Senior Notes.
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 of December 31, 2019 and 2018, Opco was in compliance with the
terms of the financial covenants contained in its debt agreements.
Opco Credit Facility
In April 2019, the Partnership entered into the Fourth Amendment (the “Fourth Amendment”) to the Opco Credit Facility
(the "Opco Credit Facility"). The Fourth Amendment extends the term of the Opco Credit Facility until April 2023. Lender
commitments under the Opco Credit Facility remain at $100.0 million.
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%.
As of December 31, 2019, the Partnership did not have any borrowings outstanding under the Opco Credit Facility and had
$100.0 million in available borrowing capacity. The weighted average interest rate for the borrowings outstanding under the Opco
Credit Facility during the year ended December 31, 2018 was 6.23%. 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.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Opco Credit Facility contains financial covenants requiring Opco to maintain:
• A leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 4.0x;
provided, however, that if the Partnership increases its quarterly distribution to its common unitholders above $0.45 per
common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from 4.0x to 3.0x;
and
•
a fixed charge coverage ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest
expense and consolidated lease expense) of not less than 3.5 to 1.0.
The 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. In addition, Opco is required to use 75% of the net cash proceeds of certain non-ordinary course asset sales to repay the
Opco Credit Facility (without any corresponding commitment reduction) and use the remaining 25% of the net cash proceeds to
offer to repay its Senior Notes on a pro-rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility
also contains customary events of default, including cross-defaults under Opco’s Senior Notes.
The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $399.7
million and $548.9 million classified as mineral rights, net and other assets, net on the Partnership’s Consolidated Balance Sheets
as of December 31, 2019 and 2018, 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, and (4) 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 December 31, 2019 and 2018, the Opco Senior Notes had cumulative principal balances of $224.1
million and $341.5 million, respectively. Opco made mandatory principal payments on the Opco Senior Notes of $117.4 million,
$80.7 million and $80.8 million during the years ended December 31, 2019, 2018 and 2017, respectively. The payments made
during the year ended December 31, 2019 included a $49.3 million pre-payment as a result of the sale of the Partnership's
construction aggregates business.
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.
In addition, the Note Purchase Agreements include a covenant that provides that, in the event NRP Operating or any of its
subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness
(including the Opco Credit Facility and all renewals, amendments or restatements thereof), such covenants shall be deemed to be
incorporated by reference in the Note Purchase Agreements and the holders of the Notes shall receive the benefit of such additional
or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement.
The 8.92% Opco Senior Notes also provides 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 December 31, 2019.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
Consolidated Principal Payments
The consolidated principal payments due are set forth below:
(In thousands)
2020
2021
2022
2023
2024
Thereafter
NRP LP
Opco
Senior Notes
Senior Notes
Credit Facility
Total
$
— $
46,176
$
— $
—
—
—
—
300,000
39,396
39,396
39,396
31,028
28,664
—
—
—
—
—
46,176
39,396
39,396
39,396
31,028
328,664
$
300,000
$
224,056
$
— $
524,056
13. Fair Value Measurements
Fair Value of Financial Assets and Liabilities
The Partnership’s financial assets and liabilities consist of cash and cash equivalents, restricted cash, contract receivable and
debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents and restricted cash
approximate fair value due to their short-term nature. There were no transfers between Level 1, Level 2 or Level 3 of the fair value
hierarchy during the years ended December 31, 2019 or 2018. The Partnership uses available market data and valuation
methodologies to estimate the fair value of its debt and contract receivable.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows the carrying amount and estimated fair value of the Partnership's debt and contract receivable:
(In thousands)
Debt:
NRP 2025 Senior Notes
NRP 2022 Senior Notes
Opco Senior Notes
Opco Credit Facility
Assets:
Contract receivable (current and long-
term)
December 31,
2019
2018
Fair Value
Hierarchy Level
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
1
1
3
3
3
$
294,084
$
269,250
$
— $
—
—
222,114
201,090
—
—
334,024
338,734
—
—
356,871
352,599
—
$
38,945
$
33,460
$
40,776
$
34,704
NRP has embedded derivatives in the preferred units related to certain conversion options, redemption features and the change
of control provision that are accounted for separately from the preferred units as assets and liabilities at fair value on the Partnership's
Consolidated Balance Sheets. Level 3 valuation of the embedded derivatives are based on numerous factors including the likelihood
of the event occurring. The embedded derivatives are revalued quarterly and changes in their fair value would be recorded in other
expenses, net on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The embedded derivatives had zero
value as of December 31, 2019 and 2018.
Fair Value of Non-Financial Assets
The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregates properties and
other assets, at fair value on a nonrecurring basis. Refer to Note 10. Mineral Rights, Net and Note 11. Intangible Assets, Net for
additional disclosures related to the fair value associated with the impaired assets.
14. Related Party Transactions
Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its management of NRP.
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. These QMC and WPPLP employee management service costs are presented as
operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of
Comprehensive Income (Loss). NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business.
These overhead costs include certain rent, information technology, administration of employee benefits and other corporate services
incurred by or on behalf of the Partnership’s general partner and its affiliates and are presented as operating and maintenance
expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
Direct general and administrative expenses charged to the Partnership by QMC and WPPLP are included on the Partnership's
Consolidated Statement of Comprehensive Income (Loss) as follows:
(In thousands)
Operating and maintenance expenses
General and administrative expenses
For the Year Ended December 31,
2019
2018
2017
$
6,436
$
6,170
$
3,548
3,658
6,184
4,989
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership had accounts payable to QMC of $0.4 million and $0.5 million on its Consolidated Balance Sheets as of
December 31, 2019 and 2018, respectively and $0.1 million of accounts payable to WPPLP as of December 31, 2019.
During the years ended December 31, 2019, 2018 and 2017, the Partnership recognized $4.0 million, $5.4 million and $1.5
million in operating and maintenance expenses, respectively, on its Consolidated Statements of Comprehensive Income (Loss)
related to an overriding royalty agreement with WPPLP. At December 31, 2019 and 2018, the Partnership had $0.1 million and
$1.4 million, respectively of accounts payable on its Consolidated Balance Sheets to WPPLP for this agreement.
Industrial Minerals Group LLC
Corbin J. Robertson, III, a Director of GP Natural Resource Partners LLC, owns a minority ownership interest in Industrial
Minerals Group LLC (“Industrial Minerals”), which, through its subsidiaries, leases two of NRP's coal royalty properties in Central
Appalachia. Coal royalty related revenues from Industrial Minerals totaled $1.7 million, $0.8 million and $0.7 million for the years
ended December 31, 2019, 2018 and 2017, respectively. The Partnership had accounts receivable from Industrial Minerals of $0.7
million and $0.1 million on its Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively.
Quinwood Coal Company Royalty
In May 2017, a subsidiary of Alpha Natural Resources assigned two coal leases with us to Quinwood Coal Company
("Quinwood"), an entity wholly owned by Corbin J. Robertson III. Coal related revenues from Quinwood totaled $0.2 million,
$0.0 million and $0.9 million for the years ended December 31, 2019, 2018 and 2017, respectively.
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 December 31, 2019, a fund controlled by Quintana Capital owned a substantial
interest in Corsa Coal Corp. ("Corsa"), a coal mining company traded on the TSX Venture Exchange that was one of the Partnership’s
lessees in Tennessee. During the second quarter of 2018, Corsa assigned its lease with NRP to a third party and is no longer deemed
a related party as of such date. Coal related revenues from Corsa totaled $0.5 million and $1.3 million for the years ended
December 31, 2018 and 2017, respectively.
Cline Affiliates and Foresight Energy
Mr. Chris Cline, both individually and through another affiliate, Adena Minerals, LLC ("Adena"), owned a 31% interest in
NRP (GP) LP, NRP's general partner ("NRP GP"), through May 9, 2017. On May 9, 2017, Adena sold its 31% limited partner
interest in NRP GP to Great Northern Properties Limited Partnership (“GNPLP”) and WPPLP (the “Adena Sale”). GNPLP and
WPPLP are companies controlled by Corbin J. Robertson, the Chairman and Chief Executive Officer of GP Natural Resource
Partners LLC (the general partner of NRP GP) (“GP LLC”). Upon closing of this transaction, NRP no longer considers the various
companies affiliated with Chris Cline, including Foresight Energy to be affiliates of NRP. As a result, all transactions (including
revenues, expenses and cash flows) after May 9, 2017 with the various companies affiliated with Chris Cline, including Foresight
Energy, are considered to be third-party transactions.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Revenues and expenses related to transactions with Foresight Energy are included on the Partnership's Consolidated
Statements of Comprehensive Income (Loss) as follows:
(In thousands)
Revenues:
Coal royalty and other (1)
Transportation and processing services (2)
Total
Operating and maintenance expenses (3)
For the Year Ended December 31,
2019
2018
2017
$
$
$
39,755
19,168
58,923
1,329
$
$
$
30,777
23,818
54,595
1,761
$
$
$
49,967
20,522
70,489
1,518
(1)
(2)
(3)
Included in 2017 coal royalty and other revenues was $21.2 million of related party revenues earned from Foresight Energy
prior to May 9, 2017.
Included in 2017 transportation and processing services revenues was $6.0 million of related party revenues earned from
Foresight Energy prior to May 9, 2017.
Included in 2017 operating and maintenance expenses was $0.5 million of related party expenses incurred from Foresight
Energy prior to May 9, 2017.
Coal Royalty and Other Revenues
Various subsidiaries of Foresight Energy lease coal reserves from the Partnership. In addition, NRP owns a contractual
overriding royalty interest at Foresight Energy's Sugar Camp mine in the Illinois Basin which provides for payments based upon
production from specific tons at Foresight Energy's Sugar Camp operations on certain reserves owned by another affiliate of Chris
Cline. Revenues related to these transactions are included in coal royalty and other revenues on the Partnership's Consolidated
Statements of Comprehensive Income (Loss).
Transportation and Processing Services Revenues and Expenses
The Partnership owns transportation and processing infrastructure related to certain of its coal properties, including loadout
and other transportation assets at Foresight Energy's Williamson and Macoupin mines in the Illinois Basin, for which it collects
throughput fees. These fees are included in transportation and processing services revenues on the Partnership's Consolidated
Statements of Comprehensive Income (Loss).
NRP is responsible for operating and maintaining the rail loadout transportation assets at the Williamson mine and subcontracts
the operating responsibilities to a subsidiary of Foresight Energy. Expenses related to these operations are included in operating
and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
In addition, NRP owns rail loadout and associated infrastructure at the Sugar Camp mine, an Illinois Basin mine also operated
by a subsidiary of Foresight Energy LP. While the Partnership owns coal reserves at the Williamson and Macoupin mines, it does
not own coal reserves at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight
Energy and NRP collects minimums and throughput fees, which are considered a return of a financing receivable or included in
transportation and processing services revenues on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
See Note 18. Financing Transaction for more information.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
15. Major Customers
Revenues from customers that exceeded 10 percent of total revenues for any of the periods presented below are as follows:
(In thousands)
Foresight Energy (1)
Contura Energy (1) (2)
2019
2018
2017
Revenues
Percent
Revenues
Percent
Revenues
Percent
$
58,923
40,743
22.9% $
15.8%
54,595
24,580
21.7% $
9.8%
70,489
20,172
29.0%
8.3%
For the Year Ended December 31,
(1) Revenues from Foresight Energy and Contura Energy are included within the Partnership's Coal Royalty and Other segment.
(2)
In the fourth quarter of 2018, Contura Energy and Alpha Natural Resources merged. Revenues during the year ended
December 31, 2019 relate to the combined company, while revenues during the year ended December 31, 2018 do not include
revenues from Alpha Natural Resources until the date of the merger. Revenues during the year ended December 31, 2017
do not include revenues from Alpha Natural Resources.
16. 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 ordinary course matters
will not have a material effect on the Partnership’s financial position, liquidity or operations. During 2019, NRP was also involved
in the legal proceeding described below.
In January 2013, NRP acquired a non-controlling 48.51% general partner interest in OCI Wyoming, L.P. ("OCI LP") and all
of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited
partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko").
The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical
Corporation.
The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by NRP if certain
performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015.
For those years, NRP paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment
obligations.
In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical
Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, NRP exchanged the stock
of OCI Co for a limited partner interest in OCI LP. Following the reorganization, NRP's interest in OCI LP remained at 49%,
consisting of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues,
management or control of OCI LP.
In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC in the District Court of Harris County, Texas, 157th
Judicial District. The complaint alleged that the transactions conducted in 2013 triggered an acceleration of NRP's obligation under
the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of
such amount, together with interest, court costs and attorneys’ fees.
In November 2019, the trial court ruled in NRP’s favor in all respects, including that the internal restructuring that occurred
did not trigger an acceleration of the contingent purchase price payment obligation under the purchase agreement with Anadarko.
Accordingly, the trial court ordered that Anadarko take nothing. Anadarko did not appeal the trial court's ruling, and this case is
concluded with no liability to the Partnership.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Environmental Compliance
The operations the Partnership’s lessees conduct on its properties, as well as the industrial minerals, aggregates and oil and
gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. See
"Items 1. and 2. Business and Properties—Regulation and Environmental Matters." As an owner of surface interests in some
properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of
substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including
environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by
the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things,
environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership makes regular visits
to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. The Partnership
believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply
with environmental laws and regulations will have a material impact on the Partnership’s financial condition or results of operations.
The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to
its properties for the period ended December 31, 2019. The Partnership is not associated with any material environmental
contamination that may require remediation costs. However, the Partnership’s lessees are required to conduct reclamation work
on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, the Partnership
is not responsible for the costs associated with these reclamation operations.
As a former owner of the working interests in oil and natural gas operations, the Partnership is responsible for its proportionate
share of any losses and liabilities, including environmental liabilities, arising from uninsured and underinsured events during the
period it was an owner.
17. Unit-Based Compensation
2017 Long-Term Incentive Plan
In December 2017, the 2017 Long-Term Incentive Plan (the “2017 LTIP”) was approved and it became effective in January
2018. The 2017 LTIP authorizes 800,000 common units that are available for delivery by the Partnership pursuant to awards under
the plan. The term is 10 years from the date of approval of the Board of Directors or, if earlier, the date the 2017 LTIP is terminated
by the Board of Directors or the committee appointed by the Board of Directors to administer the 2017 LTIP, or the date all available
common units available have been delivered. Common units delivered pursuant to the 2017 LTIP will consist, in whole or part,
of (i) common units acquired in the open market, (ii) common units acquired from the Partnership (including newly issued units),
any of our affiliates or any other person or (iii) any combination of the foregoing.
Employees, consultants and non-employee directors of the Partnership, the General Partner, GP LLC and their affiliates are
generally eligible to receive awards under the 2017 LTIP. The 2017 LTIP provides for the issuance of a variety of equity-based
grants, including grants of (i) options, (ii) unit appreciation rights, (iii) restricted units, (iv) phantom units, (v) cash awards, (vi)
performance awards, (vii) distribution equivalent rights, and (viii) other unit-based awards. The plan is administered by the
Compensation, Nominating and Governance Committee ("CNG Committee") of the Board of Directors, which determines the
terms and conditions of awards granted under the 2017 LTIP. The Partnership recognizes forfeitures for any awards issued under
this plan as they occur.
Unit-Based Awards
Unit-based awards under the 2017 LTIP are generally issued to certain employees and non-employee directors of the
Partnership. Awards granted to employees vest at the end of a 3 year period and awards granted to non-employee directors are
immediately vested. Directors are given the option to take immediate issuance of the vested awards or defer such issuance until a
later date. Upon deferral of issuance, such units will continue to accumulate distribution equivalent rights ("DERs") until issuance.
In connection with the phantom unit awards, the CNG Committee also granted tandem 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.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The awards granted in 2019 and 2018 were valued using the closing price of NRP's units as of the grant date. The grant date
fair value of these awards granted during the years ended December 31, 2019 and 2018 were $5.4 million and $2.2 million,
respectively. Total unit-based compensation expense associated with these awards was $2.4 million and $1.1 million for the years
ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses and operating and
maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The unamortized cost
associated with unvested outstanding awards as of December 31, 2019 is $3.5 million, which is to be recognized over a weighted
average period of 2.0 years. The unamortized cost associated with unvested outstanding awards as of December 31, 2018 was $1.2
million.
A summary of the unit activity in the outstanding grants during 2019 is as follows:
(In thousands)
Outstanding grants at January 1, 2019
Granted
Fully vested and issued
Forfeitures
Outstanding at December 31, 2019
18. Financing Transaction
Common Units
Weighted
Average
Exercise Price
55
$
129
$
(12) $
(15) $
$
157
29.10
41.41
41.47
37.33
37.48
The Partnership owns rail loadout and associated infrastructure at the Sugar Camp mine in the Illinois Basin operated by a
subsidiary of Foresight Energy. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight Energy and is
accounted for as a financing transaction (the "Sugar Camp lease"). The Sugar Camp lease expires in 2032 with renewal options
for up to 80 additional years. Minimum payments are $5.0 million per year through the end of the lease term. The Partnership is
also entitled to variable payments in the form of throughput fees determined based on the amount of coal transported and processed
utilizing the Partnership's assets. In the event the Sugar Camp lease is renewed beyond 2032, payments become a fixed $10 thousand
per year for the remainder of the renewed term.
The following table shows certain amounts related to the Partnership's Sugar Camp lease through 2032:
(In thousands)
Accounts receivable
Contract receivable (current and long-term)
Unearned income
Projected remaining payments
19. Leases
Lessee Accounting
December 31,
2019
2018
540
$
38,945
21,889
61,374
$
661
40,776
25,058
66,495
$
$
As of December 31, 2019, the Partnership had one operating lease for an office building that is owned by WPPLP. On January
1, 2019, the Partnership entered into a new lease of the building with a five-year base term and five additional five-year renewal
options. Upon lease commencement and as of December 31, 2019, the Partnership was reasonably certain to exercise all renewal
options included in the lease and capitalized the right-of-use asset and corresponding lease liability on its Consolidated Balance
Sheet using the present value of the future lease payments over 30 years. The Partnership's right-of-use asset and lease liability
included within other assets and other non-current liabilities, respectively, on its Consolidated Balance Sheet totaled $3.5 million
at both January 1, 2019 and December 31, 2019. During the year ended December 31, 2019, the Partnership incurred total operating
lease expenses of $0.5 million, included in both operating and maintenance expenses and general and administrative expenses on
its Consolidated Statement of Comprehensive Income (Loss).
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table details the maturity analysis of the Partnership's operating lease liability and reconciles the undiscounted
cash flows to the operating lease liability included on its Consolidated Balance Sheet:
Remaining Annual Lease Payments (In thousands)
2020
2021
2022
2023
2024
After 2024
Total lease payments (1)
Less: present value adjustment (2)
Total operating lease liability
December 31, 2019
483
483
483
483
483
11,597
14,012
(10,506)
3,506
$
$
$
(1) The remaining lease term of the Partnership's operating lease is 29 years.
(2) The present value of the operating lease liability on the Partnership's Consolidated Balance Sheet was calculated using a
13.5% discount rate which represents the Partnership's estimated incremental borrowing rate under the lease. As the
Partnership's lease does not provide an implicit rate, the Partnership estimated the incremental borrowing rate at the time the
lease was entered into by utilizing the rate of the Partnership's secured debt and adjusting it for factors that reflect the profile
of borrowing over the 30-year expected lease term.
Lessor Accounting
The Partnership owns loadout and other transportation assets at the Partnership's Macoupin property in the Illinois Basin
which is operated by Foresight Energy. The infrastructure at the Macoupin property is leased to a subsidiary of Foresight Energy
and is accounted for as an operating lease under ASC 842. The lease with Macoupin expires in January 2108. From the inception
of this lease in 2009 through January 2039, the lease provides that the Partnership is entitled to variable lease payments in the form
of throughput fees determined based on the amount of coal transported and processed utilizing the Partnership's assets. These fees
are included in transportation and processing services revenues on the Partnership's Consolidated Statements of Comprehensive
Income (Loss) and were $4.8 million, $5.0 million and $4.2 million in the years ended December 31, 2019, 2018 and 2017,
respectively. After January 2039, the lease provides that the Partnership is entitled to an annual rent of $10 thousand per year in
place of the variable lease payments.
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Quarterly Financial Data
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following table summarizes quarterly financial data for 2019:
(In thousands, except per unit data)
Revenues
Gain (loss) on asset sales and disposals
Asset impairments
Income (loss) from operations
Loss on extinguishment of debt
Net income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Net income (loss) attributable to NRP
Net income (loss) attributable to common
unitholders and general partner
Income (loss) from continuing operations per
common unit
Basic
Diluted
Net income (loss) per common unit
Basic
Diluted
Weighted average number of common units
outstanding (basic)
Weighted average number of common units
outstanding (diluted)
First
Quarter
Second
Quarter (1)
Third
Quarter
Fourth
Quarter (2)
$
66,785
$
81,223
$
57,602
$
256
—
49,939
—
35,765
(46)
35,719
35,719
246
—
60,844
29,282
19,106
245
19,351
19,351
6,107
484
49,594
—
39,163
7
39,170
39,170
$
51,827
(111)
147,730
(109,056)
—
(119,448)
750
(118,698)
(118,698)
Total
2019
257,437
6,498
148,214
51,321
29,282
(25,414)
956
(24,458)
(24,458)
28,219
11,851
31,670
(126,198)
(54,458)
$
$
$
$
2.26
1.75
2.26
1.75
$
$
0.93
0.85
0.95
0.87
$
$
2.53
1.66
2.53
1.66
(10.15) $
(10.15)
(10.09) $
(10.09)
(4.43)
(4.43)
(4.35)
(4.35)
12,255
12,261
12,261
12,261
12,260
20,015
13,388
23,157
12,261
12,260
(1) During the second quarter of 2019 the Partnership incurred a $29.3 million loss on extinguishment of debt related to the
105.250% premium paid to redeem the 2022 Senior Notes as well as the write-off of unamortized debt issuance costs and
debt discount related to the 2022 Senior Notes. See Note 12. Debt, Net for more information.
(2) During the fourth quarter of 2019 the Partnership recorded $147.7 million of asset impairments primarily related to its coal
royalty properties and intangible assets. See Note 10. Mineral Rights, Net and Note 11. Intangible Assets, Net for more
information.
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NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following table summarizes quarterly financial data for 2018:
(In thousands, except per unit data)
Revenues
Gain on litigation settlement
Gain on asset sales and disposals
Asset impairments
Income from operations
Net income from continuing operations
Income (loss) from discontinued operations
Net income
Net income attributable to NRP
Net income attributable to common
unitholders and general partner
Income from continuing operations per
common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
Weighted average number of common units
outstanding (basic)
Weighted average number of common units
outstanding (diluted)
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter (1)(2)(3)
Total
2018
$
59,478
$
69,451
$
58,207
$
63,935
$
251,071
—
651
242
44,236
26,286
(1,948)
24,338
24,338
—
168
—
52,863
35,129
2,981
38,110
37,241
—
—
—
43,346
25,853
2,688
28,541
28,900
25,000
1,622
18,038
52,093
35,092
13,966
49,058
49,058
25,000
2,441
18,280
192,538
122,360
17,687
140,047
139,537
16,838
29,741
21,400
41,558
109,537
$
$
$
$
1.50
1.16
1.35
1.08
$
$
2.14
1.57
2.38
1.71
$
$
1.50
1.18
1.71
1.30
$
$
2.21
1.69
3.33
2.36
7.35
5.90
8.77
6.76
12,238
12,246
12,246
12,247
12,244
22,125
21,383
21,840
20,394
20,234
(1) During the fourth quarter of 2018 the Partnership recorded $25 million in other income related to the Hillsboro litigation
settlement.
(2) During the fourth quarter of 2018 the Partnership sold its construction aggregates business for $205 million, before customary
purchase price adjustments and transaction expenses, and recorded a gain of $13.1 million included in income from
discontinued operations on the Partnership's Consolidated Statements of Comprehensive Income (Loss). See Note 4.
Discontinued Operations for more information.
(3) During the fourth quarter of 2018 the Partnership recorded $18.0 million in aggregates and coal property impairments. See
Note 10. Mineral Rights, Net for more information.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as
defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2019. This evaluation was performed under the supervision
and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural
Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officer and Chief Financial
Officer concluded that these disclosure controls and procedures were effective as of December 31, 2019 at the reasonable assurance
level in producing the timely recording, processing, summary and reporting of information and in accumulation and communication
of information to management to allow for timely decisions with regard to required disclosures.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such
term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management,
including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general
partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019
based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission "2013 Framework" (COSO). Based on that evaluation, as of December 31, 2019, our management
concluded that our internal control over financial reporting was effective at a reasonable assurance level based on those criteria.
No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s consolidated financial
statements included in this Annual Report on Form 10-K, has issued a report on the Partnership’s internal control over financial
reporting, which is included herein.
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Report of Independent Registered Public Accounting Firm
The Partners of Natural Resource Partners L.P.
Opinion on Internal Control Over Financial Reporting
We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2019, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Natural Resource Partners L.P. (the Partnership)
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO
criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2019 and 2018, the related
consolidated statements of comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period
ended December 31, 2019, and the related notes and our report dated February 27, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report
on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent
with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for
our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2020
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ITEM 9B. OTHER INFORMATION
None.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER AND
CORPORATE GOVERNANCE
As a master limited partnership we do not employ any of the people responsible for the management of our properties.
Instead, we reimburse affiliates of our managing general partner, GP Natural Resource Partners LLC, for their services. The
following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC as of the date
of this Annual Report on Form 10-K. Each officer and director is elected for their respective office or directorship on an annual
basis. Subject to Board Representation and Observation Rights Agreement with Blackstone and GoldenTree, Mr. Robertson is
entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the
right to appoint one director to Blackstone.
Name
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kevin J. Craig
Kathryn S. Wilson
Gregory F. Wooten
Galdino J. Claro
Russell D. Gordy
Alexander D. Greene
S. Reed Morian
Paul B. Murphy, Jr.
Richard A. Navarre
Corbin J. Robertson, III
Stephen P. Smith
Leo A. Vecellio, Jr.
Age
Position with the General Partner
72 Chairman of the Board and Chief Executive Officer
58 President and Chief Operating Officer
45 Chief Financial Officer and Treasurer
51 Executive Vice President, Coal
45 Vice President, General Counsel and Secretary
63 Vice President, Chief Engineer
60 Director
69 Director
61 Director
74 Director
60 Director
59 Director
49 Director
58 Director
73 Director
Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource
Partners LLC since 2002. Mr. Robertson has vast business experience having founded and served as a director and as an officer
of multiple companies, both private and public, and has served on the boards of numerous non-profit organizations. He has served
as the Chief Executive Officer and Chairman of the Board of the general partner of Great Northern Properties Limited Partnership
since 1992 and Quintana Minerals Corporation since 1978, as Chairman of the Board of Directors of New Gauley Coal Corporation
since 1986, and the general partner of Western Pocahontas Properties Limited Partnership since 1986. In addition, Mr. Robertson
served as Chief Executive Officer of the general partner of Western Pocahontas Properties Limited Partnership from 1986 until
2008 and currently serves on the Board of Managers of Premium Resources, LLC. He also serves as a Principal with Quintana
Capital Group, Chairman of the Board of the Cullen Trust for Higher Education and on the boards of the American Petroleum
Institute, the National Petroleum Council, the Baylor College of Medicine and the Spirit Golf Association. In 2006, Mr. Robertson
was inducted into the Texas Business Hall of Fame. Mr. Robertson is the father of Corbin J. Robertson, III.
Craig W. Nunez has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since August
2017 and previously served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC from January 2015 to
August 2017. Prior to joining NRP, Mr. Nunez was an owner and Chief Executive Officer of Bocage Group, a private investment
company specializing in energy, natural resources and master limited partnerships since March 2012. In addition, until joining
NRP, he was a FINRA-registered Investment Advisor Representative with Searle & Co since July 2012 and served as an Executive
Advisor to Capital One Asset Management since January 2014. From September 2011 through March 2012, Mr. Nunez served as
the Executive Vice President and Chief Financial Officer of Quicksilver Resources Canada, Inc. Mr. Nunez was Senior Vice
President and Treasurer of Halliburton Company from January 2007 until September 2011, and Vice President and Treasurer of
Halliburton Company from February 2006 to January 2007. Prior to that, he was Treasurer of Colonial Pipeline Company from
November 1995 to February 2006. Mr. Nunez has been involved in numerous charitable organizations and currently serves on the
boards of Goodwill Industries of Houston and Medical Bridges, Inc.
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Christopher J. Zolas has served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC since August
2017 and previously served as Chief Accounting Officer of GP Natural Resource Partners from March 2015 to August 2017. Prior
to joining NRP, Mr. Zolas served as Director of Financial Reporting at Cheniere Energy, Inc., a publicly traded energy company,
where he performed financial statement preparation and analysis, technical accounting and SEC reporting for five separate SEC
registrants, including a master limited partnership. Mr. Zolas joined Cheniere Energy, Inc. in 2007 as Manager of SEC Reporting
and Technical Accounting and was promoted to Director in 2009. Prior to joining Cheniere Energy, Inc., Mr. Zolas worked in
public accounting with KPMG LLP from 2002 to 2007.
Kevin J. Craig has served as Executive Vice President, Coal of GP Natural Resource Partners since September 2014. Mr.
Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr. Craig also represents
NRP as one of its appointees to the Board of Managers of Ciner Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX
Transportation, where he served as Terminal Manager for the West Virginia Coalfields. He has extensive marketing, finance and
operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates having
been elected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate
Craig served as Chairman of the Committee on Energy. Mr. Craig did not seek re-election in 2014 and his term ended January
2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig has served as the Chairman of the
Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber
of Commerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He is involved in numerous
state coal associations and serves as a member of the Board of Directors of BrickStreet Mutual Insurance Company.
Kathryn S. Wilson has served as Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC since
December 2013. Ms. Wilson served as Associate General Counsel from March 2013 to December 2013. Since October 2013, Ms.
Wilson has also served as General Counsel and Secretary of each of New Gauley Coal Corporation and the general partner of
Western Pocahontas Properties Limited Partnership. She served as General Counsel of Quintana Minerals Corporation from October
2013 to November 2018 and as General Counsel of the General Partner of Great Northern Properties Limited Partnership from
October 2013 to June 2019. Ms. Wilson practiced corporate and securities law with Vinson & Elkins L.L.P. from September 2001
to February 2010 and from November 2011 to February 2013. Ms. Wilson served as General Counsel of Antero Resources
Corporation from March 2010 to June 2011.
Gregory F. Wooten has served as Vice President, Chief Engineer of GP Natural Resource Partners LLC since December 2013.
Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP, Mr. Wooten served as Vice President, Chief
Operating Officer and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties
from 1982 until 2007. Mr. Wooten has over 35 years of experience in the coal industry, working as a planning and production
engineer and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers. Mr. Wooten also serves
as the President of the National Council of Coal Lessors and is a board member of the West Virginia, Kentucky, Indiana and
Montana Coal Associations. He also serves on the board of the Cabell-Huntington Hospital.
Galdino J. Claro joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Claro has 30 years
of worldwide executive leadership experience in the primary and secondary metals industries. From October 2013 to August 2017,
Mr. Claro served as the Group Chief Executive Officer and Managing Director of Sims Metal Management where he was also a
member of the Safety, Health, Environment and Sustainability Committee, the Nomination Governance Committee and the Finance
Investment Committee. Before joining Sims Metal Management, Mr. Claro served for four years as the Chief Executive Officer
of Harsco Metals and Minerals. He joined Harsco from Aleris, where he served as CEO of Aleris Americas. Before that, he was
the CEO of the Metals Processing Group of Heico Companies LLC. During his career with Alcoa Inc., Mr. Claro served for five
years as the President of Alcoa China and for six years in Europe as the Vice President of Soft Alloys Extrusions and the President
of Alcoa Europe Extrusions. While in South America, Mr. Claro worked for several different divisions of Alcoa Alumni SA as
plant manager, technology manager, new products development director and Managing Director of Alcoa Cargo-Van. Before
joining Alcoa in 1985, Mr. Claro started his career at Honda-Motogear as a Quality Control Manager where he worked for three
years in both Brazil and Japan.
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Russell D. Gordy joined the Board of Directors of GP Natural Resource Partners in October 2013. Mr. Gordy brings extensive
oil and gas industry, mineral interest and land ownership and financial experience to the Board. Mr. Gordy is currently managing
partner and majority owner in SG Interests, a producer of oil and coal bed methane gas, RGGS, which controls mineral acres
currently producing oil and gas, coal, iron ore, limestone, and copper, and Rock Creek Ranch. He is also President of Gordy Oil
Company, an oil and gas exploration company in the Gulf Coast of Texas and Louisiana, and Gordy Gas Corporation, an oil and
gas exploration company in the San Juan Basin of Colorado and New Mexico. Prior to forming SG Interests in 1989, Mr. Gordy
was a founding partner of Northwind Exploration Company an exploration company created in 1981 with former Houston Oil and
Minerals employees. Mr. Gordy served on the board of directors of Houston Exploration Company from 1987 until 2001.
Alexander D. Greene joined the Board of Directors of GP Natural Resource Partners LLC in March 2019. Mr. Greene brings
extensive corporate finance and private equity experience to his role on the Board, with more than 35 years investing in businesses
where operational improvement and strategic guidance were primary drivers of value creation and as a financial advisor to large
and mid-cap companies, boards of directors and other constituencies in complex leveraged finance, merger and acquisition and
recapitalization transactions. Mr. Greene is a director of Ambac Financial Group, Inc., Element Fleet Management Corp. and is
Chairman of the Board of USA Truck, Inc. In addition, Mr. Greene recently served as Chairman of the Board of Modular Space
Corporation prior to its sale to Williams Scotsman in 2018. From 2005 to 2014 he was a Managing Partner and head of U.S. Private
Equity at Brookfield Asset Management, a global asset management company. Prior to Brookfield, Mr. Greene was a Managing
Director and co-head of Carlyle Strategic Partners, a private equity fund, and a Managing Director and investment banker at
Wasserstein Perella & Co. and Whitman Heffernan Rhein & Co. Mr. Greene is a volunteer firefighter and president of the Armonk
Independent Fire Company and serves on the Budget and Finance Advisory Committee for the Town of North Castle, New York.
Mr. Greene has been designated to serve as a director of GP Natural Resource Partners LLC by Blackstone Tactical Opportunities,
pursuant to its right to designate a director to the Board of Directors of GP Natural Resource Partners LLC.
S. Reed Morian joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive
business experience having served as Chairman and Chief Executive Officer of several companies since the early 1980s and serving
on the board of other companies. Mr. Morian has served as a member of the Board of Directors of the general partner of Western
Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great
Northern Properties Limited Partnership since 1992. Mr. Morian also serves on the Board of Managers of Premium Resources,
LLC since 2006. Mr. Morian worked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief
Executive Officer from 1981 to 2006. He has also served as Chairman, Chief Executive Officer and President of DX Holding
Company since 1989. He formerly served on the Board of Directors for the Federal Reserve Bank of Dallas-Houston Branch from
April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March 2005 until April 2009.
Paul B. Murphy, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Murphy is the
Chairman and Chief Executive Officer and a Director of Cadence Bancorporation and Chairman of Cadence Bank, N.A. He has
served at Cadence and its predecessors since December 2009. Cadence is a $17 billion bank holding company headquartered in
Houston and it is traded on the NYSE (CADE). Previously, Mr. Murphy spent 20 years at Amegy Bank of Texas, helping to steer
that institution from $75 million in assets and a single location to assets of $11 billion and 85 banking centers at the time of his
departure as the Chief Executive Officer and a Director in 2009. Mr. Murphy is an advocate of the community and is a board
member of Oceaneering International, Inc., Hope and Healing Center and Institute, Houston Hispanic Chamber of Commerce,
and the City of Houston Complete Advisory Board.
Richard A. Navarre joined the Board of Directors of GP Natural Resource Partners LLC in October 2013. Mr. Navarre brings
extensive financial, strategic planning, public company and coal industry experience to the Board of Directors. Mr. Navarre is
Chairman, President and CEO of Covia Corporation. From 1993 until 2012, Mr. Navarre held several executive positions with
Peabody Energy Corporation, including President-Americas from March 2012 to June 2012, President and Chief Commercial
Officer from January 2008 to March 2012, Executive Vice President of Corporate Development and Chief Financial Officer from
July 2006 to January 2008 and Chief Financial Officer from October 1999 to June 2008. Mr. Navarre serves on the Board of
Directors of Civeo Corporation, where he serves as Chairman, Covia Corporation, where he serves as Chairman, and Arch Coal,
where he serves as Chairman of the Compensation Committee and member of the Nominating and Governance Committee. He
is a member of the Hall of Fame of the College of Business and a member of the Board of Advisors of the College of Business
and Administration of Southern Illinois University Carbondale. He is the former Chairman of the Bituminous Coal Operators’
Association. Mr. Navarre is a Certified Public Accountant. Mr. Navarre also has been involved in numerous civic and charitable
organizations throughout his career.
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Corbin J. Robertson, III joined the Board of Directors of GP Natural Resource Partners LLC in May 2013. Mr. Robertson
has experience with investments in a variety of energy businesses, having served both in management of private equity firms and
having served on several boards of directors. Mr. Robertson has served as a Co-Managing Partner of LKCM Headwater Investments
GP, LLC, LKCM Headwater Investments I, L.P., LKCM Headwater Investments II, LP, LKCM Headwater Investments II Sidecar,
LP, LKCM Headwater Investments III, private equity funds that began June 2011. He has served as the Chief Executive Officer
of the general partner of Western Pocahontas Properties Limited Partnership since May 2008, and has served on the Board of
Directors of Quintana Minerals Corporation since 2007 and Western Pocahontas since October 2012. Mr. Robertson also has served
on the Board of Managers of Premium Resources, LLC since 2016. Mr. Robertson also co-founded Quintana Energy Partners, an
energy-focused private equity firm in 2006, and served as a Managing Director thereof from 2006 until December
2010. Mr. Robertson has served on the Board of Directors for Quintana Minerals Corporation since October 2007, and previously
served as Vice President-Acquisitions for GP Natural Resource Partners LLC from 2003 until 2005. Mr. Robertson also serves on
the Board of Directors of Quality Magnetite, Quinwood Coal and LL&B Minerals, each of which is in the energy business.
Mr. Robertson is the son of Corbin J. Robertson, Jr.
Stephen P. Smith joined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive
public company financial experience in the power and energy industries to the Board of Directors. Mr. Smith formerly served as
Chief Financial Officer, Chief Accounting Officer and Director of the general partner of Columbia Pipeline Partners L.P. from
September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and Chief Financial Officer of
Columbia Pipeline Group from July 2015 to June 2016. Mr. Smith served as Executive Vice President and Chief Financial Officer
for NiSource, Inc. from August 2008 to June 2015. Prior to joining NiSource, he held several positions with American Electric
Power Company, Inc, including Senior Vice President - Shared Services from January 2008 to June 2008, Senior Vice President
and Treasurer from January 2004 to December 2007, and Senior Vice President - Finance from April 2003 to December 2003.
Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings
extensive experience in the aggregates and coal mine development industry to the Board of Directors. Mr. Vecellio and his family
have been in the aggregates materials and construction business since the late 1930s. Since November 2002, Mr. Vecellio has
served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer, contractor and oil terminal
developer/operator in the Mid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various
capacities with Vecellio & Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996
to November 2002. Mr. Vecellio is the former Chairman of the American Road and Transportation Builders and is a longtime
member of the Florida Council of 100, as well as many other civic and charitable organizations.
Corporate Governance
Board Meetings and Executive Sessions
The Board met eight times in 2019. During 2019, our non-management directors met in executive session several times.
The presiding director was Mr. Vecellio, the Chairman of our Compensation, Nominating and Governance Committee, or CNG
Committee. In addition, our independent directors met one time in executive session in December 2019. Mr. Vecellio was the
presiding director at that meeting. Interested parties may communicate with our non-management directors by writing a letter to
the Chairman of the CNG Committee, NRP Board of Directors, 1201 Louisiana Street, Suite 3400, Houston, Texas 77002.
Independence of Directors
The Board of Directors has affirmatively determined that Messrs. Claro, Gordy, Navarre, Smith and Vecellio are independent
based on all facts and circumstances considered by the Board, including the standards set forth in Section 303A.02(a) of the NYSE’s
listing standards. Because we are a limited partnership as defined in Section 303A of the NYSE’s listing standards, we are not
required to have a majority of independent directors on the Board. The Board has an Audit Committee, a Compensation, Nominating
and Governance Committee, and a Conflicts Committee, each of which is staffed solely by independent directors.
Audit Committee
Our Audit Committee is comprised of Mr. Smith, who serves as chairman, Mr. Claro and Mr. Navarre. Mr. Smith and Mr.
Navarre are "Audit Committee Financial Experts" as determined pursuant to Item 407 of Regulation S-K. During 2019, the Audit
Committee met seven times.
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Report of the Audit Committee
Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the
independence and experience requirements of the New York Stock Exchange. The Audit Committee has adopted, and annually
reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements. The Audit
Committee Charter is available on our website at www.nrplp.com and is available in print upon request.
During 2019, at each of its meetings, the Audit Committee met with the senior members of our financial management team,
our general counsel and our independent auditors. The Audit Committee had private sessions at certain of its meetings with our
independent auditors and the senior members of our financial management team and the general counsel at which candid discussions
of financial management, accounting and internal control and legal issues took place.
The Audit Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended
December 31, 2019 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the
results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our
financial reporting.
Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a
discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting
judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s
accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications
prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial
statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both
management and auditors their general preference for conservative policies when a range of accounting options is available.
The Audit Committee has discussed with the independent auditors the matters required to be discussed by the applicable
requirements of the Public Company Accounting Oversight Board (“PCAOB”) and the Commission. The Audit Committee has
received the written disclosures and the letter from the independent accountant required by applicable requirements of the PCAOB
regarding the independent accountant’s communications with the Audit Committee concerning independence, and has discussed
with the independent accountant the independent accountant’s independence.
In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Audit Committee reviews
our Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K prior to filing with the Securities and Exchange
Commission. In 2019, the Audit Committee also reviewed quarterly earnings announcements with management and representatives
of the independent auditor in advance of their issuance. In its oversight role, the Audit Committee relies on the work and assurances
of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors,
who, in their report, express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting
principles.
In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has
recommended to the Board of Directors, and the Board has approved, that the audited financial statements be included in our
Annual Report on Form 10-K for the year ended December 31, 2019, for filing with the Securities and Exchange Commission.
Stephen P. Smith, Chairman
Galdino J. Claro
Richard A. Navarre
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Compensation, Nominating and Governance Committee
Executive officer compensation is administered by the CNG Committee, which is currently comprised of three members:
Mr. Vecellio, as Chairman, Mr. Gordy and Mr. Smith. The CNG Committee has reviewed and approved the compensation
arrangements described in the Compensation Discussion and Analysis section of this Annual Report on Form 10-K. During 2019,
the CNG Committee met four times. Our Board of Directors appoints the CNG Committee and delegates to the CNG Committee
responsibility for:
•
•
•
reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates
to our business;
reviewing and recommending the annual and long-term incentive plans in which our executive officers participate and
approving awards thereunder; and
reviewing and approving compensation for the Board of Directors.
Our Board of Directors has determined that each CNG Committee member is independent under the listing standards of the
NYSE and the rules of the SEC.
Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the
design and implementation of compensation programs for directors and executive officers and other data that the CNG Committee
considers as appropriate. In addition, the CNG Committee has the sole authority to retain and terminate any outside counsel or
other experts or consultants engaged to assist it in the evaluation of compensation of our directors and executive officers. The
CNG Committee Charter is available in print upon request.
Partnership Agreement
Investors may view our partnership agreement and the amendments to the partnership agreement on our website at
www.nrplp.com. The partnership agreement is also filed with the SEC and is available in print to any unitholder that requests them.
Corporate Governance Guidelines and Code of Business Conduct and Ethics
We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that
applies to our management, and complies with Item 406 of Regulation S-K. Our Corporate Governance Guidelines and our Code
of Business Conduct and Ethics are available on our website at www.nrplp.com and are available in print upon request.
NYSE Certification
Pursuant to Section 303A of the NYSE Listed Company Manual, in 2019, Corbin J. Robertson, Jr. certified to the NYSE
that he was not aware of any violation by the Partnership of NYSE corporate governance listing standards.
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ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Overview
As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a
typical public corporation. Our executive officers based in Houston, Texas are employed by Quintana Minerals Corporation
(“Quintana”), and our executive officers based in Huntington, West Virginia are employed by Western Pocahontas Properties
Limited Partnership (“Western Pocahontas”). Quintana and Western Pocahontas are controlled by our Chairman and Chief
Executive Officer and are affiliates of NRP. While our executive officers are employed by affiliates of NRP, each of them has been
appointed to serve as an executive officer of GP Natural Resource Partners LLC (“GP LLC”), the general partner of NRP (GP)
LLC (“NRP GP”), the general partner of NRP. For a more detailed description of our structure, see "Items 1. and 2. Business and
Properties—Partnership Structure and Management" in this Annual Report on Form 10-K.
Although our executives’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse
those companies based on the time allocated to NRP by each executive officer. Our reimbursement for the compensation of executive
officers is governed by our partnership agreement. For purposes of this Compensation Discussion and Analysis, our “named
executive officers” are:
• Corbin J. Robertson, Jr.—Chairman and Chief Executive Officer
• Craig W. Nunez—President and Chief Operating Officer
• Christopher J. Zolas—Chief Financial Officer and Treasurer
• Kathryn S. Wilson—Vice President, General Counsel and Secretary
• Kevin J. Craig—Executive Vice President, Coal
Executive Officer Compensation Strategy and Philosophy
Under our partnership agreement, we are required to distribute all of our available cash each quarter. Historically, our primary
business objective was to generate cash flows at levels that could sustain long-term quarterly cash distributions to our investors.
However, given the difficult coal markets over the past few years, coupled with the limitations on our ability to access capital from
additional sources, our current objective is to preserve long-term equity value for our unitholders by using our excess free cash
flow to reduce our leverage. Our objective in determining the compensation of our executive officers is to retain qualified people
to manage the business under current market conditions. Incentive compensation for the year ended December 31, 2019 was
discretionary but certain performance criteria were considered as factors, as further described under “—Components of
Compensation.”
The 2019 compensation for executive officers consisted of four primary components:
•
•
•
•
base salaries;
short-term cash incentive compensation;
long-term equity incentive compensation; and
perquisites and other benefits.
To the extent our named executive officers (with the exception of Mr. Robertson) spend time on non-NRP matters, NRP
bears only the proportionate cost of their time. Mr. Robertson does not receive a salary in his capacity as Chief Executive Officer.
Mr. Robertson is compensated through short-term cash and long-term equity incentive awards, all of which is allocated to NRP.
In February of each year, the CNG Committee approves the short-term cash incentive award for the year just ended and long-
term incentive awards for the executive officers. The CNG Committee considers the performance of the partnership, the performance
of the individuals and the outlook for the future in determining the amounts of the awards.
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Each February, the CNG Committee also makes awards of phantom units to be settled in common units under the Natural
Resource Partners 2017 Long-Term Incentive Plan (the “2017 Plan”) to NRP’s officers in order to incentivize management while
also aligning the long-term interests of management with the interests of NRP’s unitholders.
Role of Compensation Experts
In 2019, the CNG Committee engaged Longnecker & Associates (“L&A”) to review our compensation practices for
named executive officers and directors relative to our peers. The CNG Committee, with input from L&A, selected our peer group
(the “Peer Group”) after reviewing annual revenue, market capitalization, total enterprise value and total assets of relevant public
companies to determine which companies were representative of the marketplace for talent within which we compete. The CNG
Committee will review the Peer Group annually to ensure continued appropriateness for comparative purposes. The CNG
Committee determined that the companies below reflect an appropriate Peer Group for 2019:
Amplify Energy Corp.
Black Stone Minerals, L.P.
Callon Petroleum Company
CatchMark Timber Trust, Inc.
Ciner Resources LP
CONSOL Coal Resources LP
Earthstone Energy, Inc.
Enviva Partner, LP
Falcon Minerals Corporation
Hi-Crush Inc.
Kimbell Royalty Partners, LP
NACCO Industries, Inc.
Panhandle Oil and Gas, Inc.
Penn Virginia Corporation
Ramaco Resources, Inc.
Rosehill Resources Inc.
SilverBow Resources, Inc.
SunCoke Energy, Inc.
Talos Energy Inc.
W&T Offshore, Inc.
Using the Peer Group, L&A conducted compensation analyses for all components of compensation and provided the CNG
Committee with its findings after such time. The findings indicated that base salaries and short-term incentive compensation of
each of the five named executive officers was generally in line with the Peer Group median, but that long-term incentive
compensation was well below the Peer Group median. While L&A provided recommendations for 2019 short-term cash incentive
compensation, 2019 base salaries and long-term incentive compensation grants were determined by the CNG Committee prior to
engaging L&A. Accordingly, the L&A recommendations will be used prospectively with respect to long-term incentive
compensation, with the goal of bringing long-term incentive compensation more in line with the Peer Group over the next few
years.
Role of Our Executive Officers in the Compensation Process
With respect to 2019 salaries and short-term cash incentive awards and long-term equity incentive awards, Mr. Nunez, our
President and Chief Operating Officer, provided Mr. Robertson with recommendations relating to the executive officers other than
himself. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of
the executive officers other than himself. Messrs. Robertson and Nunez considered the factors described elsewhere in this
compensation discussion and analysis in recommending, in their discretion, the appropriate amounts for each named executive
officer. Messrs. Robertson and Nunez attended the CNG Committee meetings at which the Committee deliberated and approved
2019 salaries, short-term cash incentive awards and long-term equity incentive awards but were excused from the meetings when
the CNG Committee discussed their compensation.
Components of Compensation
Base Salaries
With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our executive
officers are paid an annual base salary by Quintana or Western Pocahontas for services rendered to us by the executive officers
during the fiscal year. We then reimburse Quintana and Western Pocahontas based on the time allocated by each executive officer
to our business. The base salaries of our named executive officers are reviewed on an annual basis as well as at the time of a
promotion or other material change in responsibilities. The CNG Committee reviews and approves the full salaries paid to each
executive officer by Quintana and Western Pocahontas, based on both the actual time allocations to NRP in the prior year and the
anticipated time allocations in the coming year. Adjustments in base salary are based on an evaluation of individual performance,
our partnership’s overall performance during the fiscal year and the individual’s contribution to our overall performance.
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In determining salaries for NRP’s executive officers for 2019, at the December 2018 meeting, the CNG Committee considered
the financial performance of NRP for the nine months ended September 30, 2018 as well as the projected financial performance
of NRP for the fourth quarter of 2018 and for the year ending December 31, 2019. The CNG Committee also considered the
individual performance of each member of the executive management team during 2018. Salaries for 2019 are shown in the
Summary Compensation Table below.
Short-Term Cash Incentive Compensation
Each named executive officer received a discretionary short-term cash incentive award approved in February 2020 by the
CNG Committee. The amounts awarded with respect to 2019 under this program are disclosed in the Summary Compensation
Table under the Bonus column. With respect to 2019, the CNG Committee, using recommendations from L&A, determined that
cash bonuses would be paid based on a percentage of base salary, with Mr. Robertson receiving approximately two times the
amount awarded to the President and Chief Operating Officer. In addition, the CNG Committee determined that it would consider
certain criteria to determine bonus amounts within this range, but that the criteria utilized at the time of determination, as well as
the relative weight of those criteria, would be generally discretionary and subject to change based on developments at the company.
Long-Term Equity Incentive Compensation
Each named executive officer received a discretionary long-term equity incentive award in 2019 under the 2017 Plan. The
2019 awards were made in the form of phantom units that will settle in NRP common units on a one-for-one basis following vesting
in February 2022 and accrue DERs to be paid in cash upon settlement. We refer to these phantom units issued in 2019 as “2017
Plan Phantom Units.” The 2017 Plan Phantom Units are subject to forfeiture and will vest on an accelerated basis following death
or disability of the award recipient or following a change in control of NRP. The grant date fair value of the 2017 Plan Phantom
Units awarded in 2019 are disclosed in the Summary Compensation Table under the "Stock Awards" column. For the 2017 Plan
Phantom Units awarded in 2019, the CNG Committee generally awarded an amount equal to 135% to 140% of base salary, with
Mr. Robertson receiving two times the amount awarded to the President and Chief Operating Officer. The CNG Committee
considered performance of the company and individual performance in making these awards.
Perquisites and Other Personal Benefits
Both Quintana and Western Pocahontas maintain employee benefit plans that provide our executive officers and other
employees with the opportunity to enroll in health, dental and life insurance plans. Each of these benefit plans require the employee
to pay a portion of the health and dental premiums, with the company paying the remainder. These benefits are offered on the same
basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee
allocates time to our business.
In 2019, Quintana and Western Pocahontas maintained tax-qualified 401(k) plans. During 2019, Quintana and Western
Pocahontas matched 100% of the first 6.0% of the employee contributions under their respective 401(k) plans. As with the other
contributions, any amounts contributed by Quintana and Western Pocahontas are reimbursed by us based on the time allocated by
the employee to our business. None of NRP, Quintana or Western Pocahontas maintains a pension plan or a defined benefit
retirement plan.
Unit Ownership Requirements
NRP maintains Unit Ownership and Retention Guidelines (the “ownership guidelines”) that are administered by the CNG
Committee and require NRP’s officers who are required to file ownership reports under Section 16 of the Securities Exchange Act
of 1934 (the “Exchange Act”) and certain other officers as designated from time-to-time by the Board or the CNG Committee to
retain all common units awarded under any NRP incentive plan (net of any units withheld or sold to cover tax liabilities) until
certain ownership guidelines are met. The guideline for NRP’s President and Chief Operating Officer and Chief Financial Officer
is for such individuals to hold common units having a value of three times his or her base salary at the date of measurement. The
guideline for NRP’s Executive Vice President—Coal is for such individual to hold common units having a value of two times his
or her base salary at the date of measurement. The guideline for NRP’s Vice President & General Counsel and is for such individual
to hold common units having a value of one and one-half times his or her base salary at the date of measurement. There is no
minimum time period required to achieve the unit ownership guidelines. Due to his substantial ownership in NRP, the ownership
guidelines do not currently apply to our Chief Executive Officer.
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The ownership guidelines also require directors who are not officers to retain common units with a value equal to three times
the amount of the annual cash retainer paid to directors. Directors are required to achieve the unit ownership guideline within five
years. Until the unit ownership guideline is achieved, each director is encouraged to retain all common units awarded under any
NRP incentive plan (net of any units sold to cover tax liabilities).
Units that count towards the satisfaction of the officer and director guidelines include common units held directly by the
executive officer or director, common units owned indirectly by the executive officer or director (e.g., by a spouse or other immediate
family member residing in the same household or a trust for the benefit of the executive officer or director or his or her family),
units granted under NRP’s long-term incentive plans (including phantom units representing the right to receive units), and units
purchased in the open market (whether purchased before or after the effective date of the ownership guidelines).
Incentive Compensation Recoupment Policy
NRP maintains the Natural Resource Partners L.P. Incentive Compensation Recoupment Policy, which is administered by
the CNG Committee. The policy authorizes the Board or committee thereof to recoup incentive compensation in the event of a
restatement of financial statements due to material non-compliance with securities laws, fraud or misconduct.
Securities Trading Policy
Our insider trading policy states that executive officers and directors may not purchase or sell puts or calls to sell or buy our
common units, engage in short sales with respect to our common units, or buy our securities on margin.
Report of the Compensation, Nominating and Governance Committee
The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of
Regulation S-K with management. Based on the reviews and discussions referred to in the foregoing sentence, the CNG Committee
recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for
the year ended December 31, 2019.
Leo A. Vecellio, Jr., Chairman
Russell D. Gordy
Stephen P. Smith
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Summary Compensation Table
The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation for 2017, 2018
and 2019:
Name and Principal Position
Year
Salary ($)
Bonus ($)
Corbin J. Robertson, Jr.—Chief Executive Officer
938,868
—
— 1,208,247
—
—
2019
2018
2017
Non-Equity
Incentive Plan
Compensation
($)
Stock Awards
($) (1)
All Other
Compensation
($) (2)
Total ($)
— 1,306,222
418,836
—
250,000
3,250,000
—
—
—
2,245,090
1,877,083
3,250,000
Craig W. Nunez—President and Chief Operating Officer
2019
2018
2017
500,000
447,499
375,000
408,204
604,124
250,000
—
93,750
1,218,750
653,111
209,433
—
16,800
16,800
34,650
1,578,115
1,371,606
1,878,400
Christopher J. Zolas—Chief Financial Officer
2019
2018
2017
355,000
337,499
300,000
284,000
455,624
180,000
—
75,000
375,000
492,581
167,529
—
16,800
16,800
34,650
1,148,381
1,052,452
889,650
Kathryn S. Wilson—Vice President, General Counsel and Secretary(3)
2019
2018
2017
272,217
469,124
150,000
340,271
347,499
321,750
—
75,000
975,000
507,178
139,622
—
16,128
16,800
34,304
1,135,794
1,048,045
1,481,054
Kevin J. Craig—Executive Vice President, Coal(4)
310,500
229,839
172,000
2019
2018
2017
248,400
321,775
145,600
—
75,000
375,000
434,854
145,209
—
15,120
13,200
22,427
1,008,874
785,023
715,027
(1) Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards
Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in
calculating these amounts, see "Item 8. Financial Statements and Supplementary Data—Note 17. Unit-Based
Compensation" elsewhere in this Annual Report on Form 10-K for more information.
(2) Includes portions of 401(k) matching allocated to Natural Resource Partners by Quintana and Western Pocahontas.
(3) Ms. Wilson allocated approximately 99%, 100% and 96% of her time to NRP during the years ended December 31, 2017,
2018 and 2019, respectively, and amounts included under the "Salary," "Bonus," and "All Other Compensation" columns
reflect this allocation.
(4) Mr. Craig allocated approximately 80%, 80% and 90% of his time to NRP during the years ended December 31, 2017,
2018 and 2019, respectively, and amounts included under the “Salary,” “Bonus,” and “All Other Compensation” columns
reflect this allocation
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Grants of Plan-Based Awards in 2019
The following table shows the 2017 Plan Phantom Units granted to named executive officers during 2019. The awards in
the table below will vest in February 2022, and upon settlement, an equivalent number of common units will be issued to each
named executive officer, subject to withholding. The 2017 Plan Phantom Units also accrue DERs from the grant date, which will
be paid out in cash upon settlement following and subject to vesting.
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Kevin J. Craig
Employment Agreements
Grant Date
2/14/2019
2/14/2019
2/14/2019
2/14/2019
2/14/2019
2017 Plan Phantom Units
Number of Units
31,498
15,749
11,878
12,230
10,486
Grant Date Fair Value
1,306,222
$
653,111
492,581
507,178
434,854
None of our named executive officers have an employment agreement.
Phantom Units Vested in 2019
The table below shows the cash settled phantom units issued in February 2015 under our previous long-term incentive plan
that vested in 2019 (the "Cash Settled Phantom Units") with respect to each named executive officer, along with value realized by
each individual:
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Kevin J. Craig
$
Cash Settled Phantom
Units
3,600
1,400
950
950
950
Value Realized on
Vesting(1)
166,759
64,851
44,006
44,006
44,006
(1) Includes DERs accrued from the issue date to the settlement date.
Outstanding Equity Awards at December 31, 2019
The table below shows the total number of outstanding 2017 Plan Phantom Units held by each named executive officer at
December 31, 2019.
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Kevin J. Craig
$
Unvested 2017 Plan
Phantom Units(1)
45,891
22,946
17,635
17,028
15,476
Market Value of
Unvested 2017 Plan
Phantom Units(2)
922,868
461,444
354,640
342,433
311,222
(1) 2017 Plan Phantom Units were awarded in February 2018 and 2019 and vest in February 2021 and 2022, respectively.
(2) Based on a unit price of $20.11, the closing price for the common units on December 31, 2019.
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Potential Payments upon Termination or Change in Control
Upon the occurrence of a change in control of NRP, our general partner, or GP Natural Resource Partners LLC, 2017 Plan
Phantom Units held by each of our named executive officers would immediately vest and become payable. The table below indicates
the estimated payments to each named executive officer following a change in control at December 31, 2019.
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Kevin J. Craig
2017 Plan Equity Awards
$
Unvested
Phantom Units
45,891
22,946
17,635
17,028
15,476
Market Value(2)
Accumulated
DERs
Total Potential
Payments
$
922,868
461,444
354,640
342,433
311,222
$
126,868
63,436
49,160
46,098
43,029
1,049,736
524,880
403,800
388,531
354,251
(1) Calculated based on a unit price of $20.11, the closing price for the common units on December 31, 2019.
Directors’ Compensation for the Year Ended December 31, 2019
For more information regarding the Board and committees thereof, see “Item 10. Directors and Executive Officers of the
Managing General Partner and Corporate Governance” elsewhere in this Annual Report on Form 10-K. Director compensation
during 2019 consisted of a $75,000 cash retainer and an award of common units under the 2017 Plan. The units awarded to Board
members are fully vested and not subject to forfeiture; however, the Board members had the option in advance of receipt of the
award to elect to defer settlement of the award until after 90 days following such director’s retirement or earlier departure from
the Board. In addition, members of Board committees received $5,000 for each committee served on, and each committee chairman
received an additional $10,000 for acting as chairman.
The table below shows the directors’ compensation for the year ended December 31, 2019:
Name of Director
Russell D. Gordy
Jasvinder S. Khaira(2)
S. Reed Morian
Richard A. Navarre(3)
Corbin J. Robertson, III
Stephen P. Smith(3)
Leo A. Vecellio, Jr.
Paul B. Murphy, Jr.
Galdino J. Claro
Alexander D. Greene(2)
Fees Earned or Paid in
Cash
2017 Plan Common
Unit Awards(1)
Total Compensation
$
80,000
$
81,074
$
—
75,000
95,000
75,000
95,000
95,000
75,000
85,000
—
—
81,074
81,074
81,074
81,074
81,074
81,074
81,074
—
161,074
—
156,074
176,074
156,074
176,074
176,074
156,074
166,074
—
(1) Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards
Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in
calculating these amounts, see Note 17 to the audited consolidated financial statements included elsewhere in this Annual
Report on Form 10-K.
(2) Mr. Khaira, who was the Blackstone designee pursuant to the Board Representation and Observation Rights Agreement,
resigned from the Board effective March 8, 2019. Effective on such date, Mr. Greene was appointed to the Board by
Blackstone to replace Mr. Khaira. Messrs. Khaira and Greene did not receive Board compensation as Blackstone designees.
(3) Messrs. Navarre and Smith elected to defer settlement of their common units awarded under the 2017 Plan in 2019 until
90 days following their respective retirements or earlier departures from the Board.
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The table below shows the Cash Settled Phantom Units that were granted in February 2015 and vested in 2019 with respect
to each Director, along with the value realized by each individual, including the DERs accruing from the February 2015 grant
date.
Name of Director
Russell D. Gordy
Jasvinder S. Khaira
S. Reed Morian
Richard A. Navarre
Corbin J. Robertson, III
Stephen P. Smith
Leo A. Vecellio, Jr.
Paul B. Murphy, Jr.
Galdino J. Claro
Alexander D. Greene
$
Cash Settled
Phantom Units
410
—
410
410
410
410
410
—
—
—
Value Realized
on Vesting
18,992
—
18,992
18,992
18,992
18,992
18,992
—
—
—
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2019, Messrs. Vecellio, Gordy, and Smith served on the CNG Committee. None of
Messrs. Vecellio, Gordy, and Smith has ever been an officer or employee of NRP or GP Natural Resource Partners LLC. None of
our executive officers serve as a member of the board of directors or compensation committee of any entity that has any executive
officer serving as a member of our Board or CNG Committee.
Pay Ratio Disclosure
The Securities and Exchange Commission has adopted a rule requiring annual disclosure of the ratio of the median employee’s
total annual compensation to the total annual compensation of the CEO.
The personnel providing services to us, including our executive officers, are employed by Quintana or Western Pocahontas.
As of December 31, 2019, 55 such persons were providing services to us. We identified a new median service provider for 2019
by examining the 2019 total taxable compensation, as reflected in our payroll records as reported to the Internal Revenue Service
on Form W-2, for all individuals who provided services to us as of December 31, 2019. We did not make any assumptions,
adjustments, or estimates with respect to total cash compensation or equity compensation and we did not annualize the compensation
for any service providers that were not employed for all of 2019.
After identifying the median service provider based on total compensation, we calculated annual 2019 compensation for the
median service provider using the same methodology used to calculate the Chief Executive Officer’s total compensation as reflected
in the Summary Compensation Table above. The median service provider’s annual 2019 compensation was as follows:
Name
Median Service
Provider
Year
2019
Salary
Bonus
Non-Equity
Incentive Plan
Compensation
Phantom
Unit Awards
All Other
Compensation
$
85,847
$
23,661
$
— $
— $
5,151
Total
$ 114,659
Our 2019 ratio of Chief Executive Officer total compensation to our median service provider's total compensation is reasonably
estimated to be 20:1.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following tables set forth, as of February 24, 2020, the amount and percentage of our common units and preferred units
beneficially held by (1) each person known to us to beneficially own 5% or more of any class of our units, (2) by each of our
directors and named executive officers and (3) by all directors and executive officers as a group. Unless otherwise noted, each of
the named persons and members of the group has sole voting and investment power with respect to the units shown.
Name of Beneficial Owner
Corbin J. Robertson, Jr. (2)
Western Pocahontas Corporation (3)
Western Pocahontas Properties Limited Partnership (4)
JPMorgan Chase & Co. (5)
The Goldman Sachs Group, Inc. (6)
Kevin J. Craig
Craig W. Nunez
Kathryn S. Wilson
Christopher J. Zolas
Galdino J. Claro
Russell D. Gordy (7)
Alexander D. Greene
S. Reed Morian (8)
Paul B. Murphy, Jr.
Richard A. Navarre
Corbin J. Robertson III (9)
Stephen P. Smith (10)
Leo A. Vecellio, Jr.
Directors and Officers as a Group
*
Less than one percent.
Common
Units
Percentage of
Common
Units (1)
2,411,395
1,739,007
1,727,986
1,050,335
835,403
950
—
—
—
4,114
11,354
—
620,513
7,614
1,000
238,656
355
6,354
19.7%
14.2%
14.1%
8.6%
6.8%
—
—
—
*
*
*
—
5.1%
*
*
1.9%
*
*
3,302,305
26.9%
(1) Percentages based upon 12,261,199 common units issued and outstanding as of February 24, 2020. Unless otherwise noted,
beneficial ownership is less than 1%.
(2) Mr. Robertson may be deemed to beneficially own 505,861 common units owned in his individual capacity, 1,739,007
common units in his capacity as controlling shareholder of Western Pocahontas Corporation, 156,000 common units in his
capacity as the sole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource
Partners, which is the general partner of NRP (GP) LP, 5,293 common units in his capacity as controlling shareholder of
GNP Management Corporation and 5,234 common units held by his spouse, Barbara M. Robertson. Mr. Robertson’s address
is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.
(3) Western Pocahontas Corporation has sole voting and sole dispositive power with respect to 11,021 common units and
shared voting and shared dispositive power with respect to 1,727,986 common units in its capacity as the general partner
of Western Pocahontas Properties Limited Partnership. The business address of Western Pocahontas Corporation is 5260
Irwin Road, Huntington, West Virginia 25705.
(4) Western Pocahontas Properties Limited Partnership has sole voting and sole dispositive power with respect to 0 common
units and shared voting and shared dispositive power with respect to 1,727,986 common units. The business address of
Western Pocahontas Properties Limited Partnership is 5260 Irwin Road, Huntington, West Virginia 25705.
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(5) According to a Schedule 13G filing with the SEC on January 31, 2020, JPMorgan Chase & Co. holds sole voting power
and sole dispositive power with respect to 1,050,335 common units in the Partnership. The business address of JPMorgan
Chase & Co. is 270 Park Ave., New York, NY 10017.
(6) According to a Schedule13G filing with the SEC on January 31, 2020, The Goldman Sachs Group holds shared voting
power and shared dispositive power with respect to 835,403 common units in the Partnership. The business address of The
Goldman Sachs Group is 200 West Street, New York, NY 10282.
(7) Mr. Gordy may be deemed to beneficially own 5,000 common units owned by Minion Trail, Ltd. and 2,000 common units
owned by Rock Creek Ranch 1, Ltd.
(8) Mr. Morian may be deemed to beneficially own 344,863 common units owned by Shadder Investments and 60,097 common
units owned by Mocol Properties.
(9) Mr. Robertson III may be deemed to beneficially own 9,783 common units held CIII Capital Management, LLC, 10,000
common units held by BHJ Investments, 19,663 common units held by The Corbin James Robertson III 2009 Family Trust
and 39 common units held by his spouse, Brooke Robertson. The address for CIII Capital Management, LLC is 1415
Louisiana Street, Suite 2400, Houston, Texas 77002, the address for BHJ Investments is 1415 Louisiana Street, Suite 2400,
Houston, Texas 77002 and the address for The Corbin James Robertson III 2009 Family Trust is 1415 Louisiana Street,
Suite 2400, Houston, Texas 77002. The following common units are pledged as collateral for loans: 51,987 common units
owned by Mr. Robertson III.
(10) Mr. Smith may be deemed to beneficially own 355 common units owned by the SP Smith 2002 Revocable Trust.
Name of Beneficial Owner
The Blackstone Group Inc. (1)
GoldenTree Asset Management, LP (2)
Preferred Units
Percentage of
Preferred Units
142,500
107,500
57%
43%
(1) The preferred units are owned by funds managed by The Blackstone Group Inc., whose address is 345 Park Ave, New
York, NY 10154. The Blackstone Group Inc. is controlled by its founder, Stephen A. Schwarzman.
(2) The preferred units are owned by funds managed by GoldenTree Asset Management, LP, whose address is 300 Park Ave,
New York, NY 10022. Steven A. Tananbaum serves as senior managing member of GoldenTree Asset Management LLC,
the general partner of GoldenTree Asset Management, LP.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, and Great Northern Properties Limited
Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer
to these companies collectively as the WPP Group. Corbin J. Robertson, Jr. owns the general partner of Western Pocahontas
Properties, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman and Chief Executive
Officer of New Gauley Coal Corporation.
Omnibus Agreement
As part of the omnibus agreement entered into concurrently with the closing of our initial public offering, the WPP Group
and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the “GP affiliates,” each agreed that
neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each,
a "restricted business") in the specific circumstances described below:
•
•
the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned
fee coal reserves within the United States; and
the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within
the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.
"Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more
intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described
below, the WPP Group and their respective controlled affiliates will not be prohibited from engaging in activities in which they
compete directly with us.
A GP affiliate may, directly or indirectly, engage in a restricted business if:
•
•
•
the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value
of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must
offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided
that if the fair market value of the assets of the restricted business subsequently exceeds $10 million, the GP affiliate
must offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the
general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under
the procedures described below.
•
its ownership in the restricted business consists solely of a non-controlling equity interest.
For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant
GP affiliate.
The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP
Group, other than those engaged in by the WPP Group at closing of our initial public offering, may not exceed $75 million. For
purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will
be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be
acquired.
If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market
value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired,
then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a
restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business
constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first
and then offer us the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph,
"restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restriction
summarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good
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faith by the relevant GP affiliate.
If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts
committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer
from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the
general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other
terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business
to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last
offered by us. During this two-year period, the GP affiliate may operate the restricted business in competition with us, subject to
the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.
If, at the end of the two year period, the restricted business has not been sold to a third party and the restricted business
retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer
the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee,
agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from
the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general
partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value
of the restricted business, then the GP affiliate will be under no further obligation to us with respect to the restricted business,
subject to the restriction on total fair market value of restricted businesses owned.
In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith
opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value
of the restricted business remains, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, the GP affiliate
will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offer procedures
described above will recommence.
If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing
member interest in a publicly held limited liability company, the WPP Group may not acquire such restricted business even if we
decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a
non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPP Group may acquire
such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures
described above.
The omnibus agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee.
The respective obligations of the WPP Group under the omnibus agreement terminate when the WPP Group and its affiliates cease
to participate in the control of the general partner.
Board Representation and Observation Rights Agreement
Effective on March 2, 2017 in connection with the closing of the issuance of the Preferred Units, we entered into the Board
Observation and Representation Rights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant
to the Board Rights Agreement, Blackstone appoints one member to serve on the Board of Directors of GP Natural Resource
Partners LLC and also appoints one observer to attend meetings of the Board. Blackstone's rights to appoint a member of the Board
and an observer will terminate at such time as Blackstone, together with their affiliates, no longer own at least 20% of the total
number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the
"Minimum Preferred Unit Threshold"). Following the time that Blackstone (and their affiliates) no longer own the Minimum
Preferred Unit Threshold and until such time as GoldenTree (together with their affiliates) no longer own the Minimum Preferred
Unit Threshold, GoldenTree shall have the one-time option to appoint either one person to serve as a member of the Board or one
person to serve as a Board observer. To the extent GoldenTree elects to appoint a Board member and later remove such Board
member, GoldenTree may then elect to appoint a Board observer. For more information on the Preferred Units, including the rights
of the holders thereof, see "Item 8. Financial Statements and Supplementary Data—Note 5. Class A Convertible Preferred Units
and Warrants" elsewhere in this Annual Report on Form 10-K.
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Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused
on investments in the energy business. NRP’s Board of Directors has adopted a formal conflicts policy that establishes the
opportunities that will be pursued by NRP and those that will be pursued by Quintana Capital. The basic tenets of the policy are
set forth below.
NRP’s business strategy has historically focused on:
• The ownership of natural resource properties in North America, including, but not limited to coal, aggregates and industrial
minerals, and oil and gas. NRP leases these properties to mining or operating companies that mine or produce the
resources and pay NRP a royalty.
• The ownership and operation of transportation, storage and related logistics activities related to extracted hard minerals.
The businesses and investments described in this paragraph are referred to as the "NRP Businesses."
NRP’s acquisition strategy also includes:
• The ownership of non-operating working interests in oil and gas properties.
• The ownership of non-controlling equity interests in companies involved in natural resource development and extraction.
• The operation of construction aggregates mining and production businesses.
The businesses and investments described in this paragraph are referred to as the "Shared Businesses."
NRP’s business strategy does not, and is not expected to, include:
• The ownership of equity interests in companies involved in the mining or extraction of coal.
•
•
Investments that do not generate "qualifying income" for a publicly traded partnership under U.S. tax regulations.
Investments outside of North America.
• Midstream or refining businesses that do not involve hard extracted minerals, including the gathering, processing,
fractionation, refining, storage or transportation of oil, natural gas or natural gas liquids.
The businesses and investments described in this paragraph are referred to as the "Non-NRP Businesses."
It is acknowledged that neither Quintana Capital nor Mr. Robertson will have any obligation to offer investments relating
to Non-NRP Businesses to NRP, and that NRP will not have any obligation to refrain from pursuing a Non-NRP Business if there
is a change in its business strategy.
For so long as Corbin Robertson, Jr. remains both an affiliate of Quintana Capital and an executive officer or director of
NRP or an affiliate of its general partner, before making an investment in an NRP Business, Quintana Capital has agreed to adhere
to the following procedures:
• Quintana Capital will first offer such opportunity in its entirety to NRP. NRP may elect to pursue such investment wholly
for its own account, to pursue the opportunity jointly with Quintana Capital or not to pursue such opportunity.
•
If NRP elects not to pursue an NRP Business investment opportunity, Quintana Capital may pursue the investment for
its own account on similar terms.
• NRP will undertake to advise Quintana Capital of its decision regarding a potential investment opportunity within 10
business days of the identification of such opportunity to the Conflicts Committee.
If the opportunity relates to the acquisition of a Shared Business, NRP and Quintana Capital will adhere to the following
procedures:
•
If the opportunity is generated by individuals other than Mr. Robertson, the opportunity will belong to the entity for
which those individuals are working.
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•
If the opportunity is generated by Mr. Robertson and both NRP and Quintana Capital are interested in pursuing the
opportunity, it is expected that the Conflicts Committee will work together with the relevant Limited Partner Advisory
Committees for Quintana Capital to reach an equitable resolution of the conflict, which may involve investments by
both parties.
In all cases above in which Mr. Robertson has a conflict of interest, investment decisions will be made on behalf of NRP by
the Conflicts Committee and on behalf of Quintana Capital Group by the relevant Investment Committee, with Mr. Robertson
abstaining.
Relationships with Entities Associated with Corbin J. Robertson, III
Quinwood Coal Partners LP (“Quinwood”), an entity controlled by Corbin J. Robertson, III (one of our directors) leases two
coal properties from us in Central Appalachia. During the year ended December 31, 2019, we recorded $0.2 million in coal royalty
revenues from Quinwood and received $0.2 million in cash related to royalty and property tax payments.
Mr. Robertson III also owns a minority ownership interest in Industrial Minerals Group LLC (“Industrial Minerals”), which,
through its subsidiaries, leases two of NRP’s coal royalty properties in Central Appalachia. During the year ended December 31,
2019, we recorded $1.7 million in coal royalty and wheelage revenues from Industrial Minerals and received approximately $0.5
million in cash related to royalty and minimum payments.
Office Building in Huntington, West Virginia
We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The
initial 10-year term of the lease expired at the end of 2018. On January 1, 2019 we entered into a new lease on the building for a
five-year base term, with five additional five-year renewal options. During the year ended December 31, 2019, we paid
approximately $0.8 million to Western Pocahontas under the lease.
Relationship with Cadence Bank, N.A.
Paul B. Murphy, Jr. one of the members of the Board of Directors of GP Natural Resource Partners LLC, is the Chairman
of Cadence Bank, N.A., which is a lender under NRP Operating’s revolving credit facility and has received customary fees and
interest payments in connection therewith. During the year ended December 31, 2019 we paid approximately $0.1 million in
interest and fees under the credit facility to Cadence Bank, N.A.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its
affiliates (including the WPP Group) on the one hand, and our partnership and our limited partners, on the other hand. The directors
and officers of GP Natural Resource Partners LLC have duties to manage GP Natural Resource Partners LLC and our general
partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage our partnership in a manner
beneficial to us and our unitholders. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware
Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary
duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership
agreement contains various provisions modifying the fiduciary duties that would otherwise be owed by our general partner with
contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Our partnership
agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability
standards, might constitute breaches of fiduciary duty under applicable Delaware law.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other
partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval
of the conflicts committee of the Board of Directors of our general partner of such resolution. The partnership agreement contains
provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving
conflicts of interest.
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Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders
if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable
to us if that resolution is:
•
•
•
approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general
partner may adopt a resolution or course of action that has not received approval;
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
fair to us, taking into account the totality of the relationships between the parties involved, including other transactions
that may be particularly favorable or advantageous to us.
In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically
provided for in the partnership agreement, consider:
•
•
•
•
the relative interests of any party to such conflict and the benefits and burdens relating to such interest;
any customary or accepted industry practices or historical dealings with a particular person or entity;
generally accepted accounting practices or principles; and
such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
Blackstone has certain consent rights and board appointment and observation rights and may be deemed to be an affiliate
of our general partner. In addition, GoldenTree has certain limited consent rights. In the exercise of these consent rights and board
rights, conflicts of interest could arise between us on the one hand, and Blackstone or GoldenTree on the other hand.
Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding
such matters as:
•
•
•
•
•
amount and timing of asset purchases and sales;
cash expenditures;
borrowings;
the issuance of additional common units; and
the creation, reduction or increase of reserves in any quarter.
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the
unitholders, including borrowings that have the purpose or effect of enabling our general partner to receive distributions.
For example, in the event we have not generated sufficient cash from our operations to pay the quarterly distribution on our
common units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding
common units.
The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.
Our general partner and its affiliates may not borrow funds from us or our subsidiaries.
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We do not have any officers or employees. We rely on officers and employees of GP Natural Resource Partners LLC and its
affiliates.
We do not have any officers or employees and rely on officers and employees of GP Natural Resource Partners LLC and its
affiliates. Affiliates of GP Natural Resource Partners LLC conduct businesses and activities of their own in which we have no
economic interest. If these separate activities are significantly greater than our activities, there could be material competition for
the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource
Partners LLC are not required to work full time on our affairs. Certain of these officers devote significant time to the affairs of the
WPP Group or its affiliates and are compensated by these affiliates for the services rendered to them.
We reimburse our general partner and its affiliates for expenses.
We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred
in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines
the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to
our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general
partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained
more favorable terms without the limitation on liability.
Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the
unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-
length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided
these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual
arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts
and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length
negotiations.
All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and
its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our
general partner or its affiliates to enter into any contracts of this kind.
We may not choose to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent auditors and others who have performed services for us in the past were retained by our general
partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent
auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform
services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in
the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of
common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law
has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
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Our general partner’s affiliates may compete with us.
The partnership agreement provides that our general partner is restricted from engaging in any business activities other than
those incidental to its ownership of interests in us. Except as provided in our partnership agreement and the Omnibus Agreement,
affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us.
The Conflicts Committee Charter is available upon request.
Director Independence
For a discussion of the independence of the members of the Board of Directors of our managing general partner under
applicable standards, see "Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance
—Corporate Governance—Independence of Directors," which is incorporated by reference into this Item 13.
Review, Approval or Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner and its affiliates (including the WPP Group)
on the one hand, and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential
conflict is addressed as described under "—Conflicts of Interest."
Pursuant to our Code of Business Conduct and Ethics, conflicts of interest are prohibited as a matter of policy, except under
guidelines approved by the Board and as provided in the Omnibus Agreement and our partnership agreement. For the year ended
December 31, 2019 there were no transactions where such guidelines were not followed.
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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended and we engaged Ernst &
Young LLP to audit our accounts and assist with tax work for fiscal 2019 and 2018. All of our audit, audit-related fees and tax
services have been approved by the Audit Committee of our Board of Directors. The following table presents fees for professional
services rendered by Ernst &Young LLP:
Audit Fees (1)
Tax Fees (2)
2019
2018
$
1,070,206
$
533,083
957,272
501,426
(1) Audit fees include fees associated with the annual integrated audit of our consolidated financial statements and internal
controls over financial reporting, separate audits of subsidiaries and reviews of our quarterly financial statement for inclusion
in our Form 10-Q and comfort letters; consents; work related to acquisitions; assistance with and review of documents
filed with the SEC.
(2) Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing
of Schedules K-1.
Audit and Non-Audit Services Pre-Approval Policy
I. Statement of Principles
Under the Sarbanes-Oxley Act of 2002 (the "Act"), the Audit Committee of the Board of Directors is responsible for the
appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee
is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do
not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the SEC has issued rules
specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s
administration of the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of
Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the "Policy"), which sets forth the procedures and
the conditions pursuant to which services proposed to be performed by the independent auditor may be pre-approved.
The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid.
Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee
("general pre-approval") or require the specific pre-approval of the Audit Committee ("specific pre-approval"). The Audit
Committee believes that the combination of these two approaches in this Policy will result in an effective and efficient procedure
to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received
general pre-approval, it will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor.
Any proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-approval by the
Audit Committee.
For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules
on auditor independence. The Audit Committee will also consider whether the independent auditor is best positioned to provide
the most effective and efficient service for reasons such as its familiarity with our business, employees, culture, accounting systems,
risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage or control risk or improve
audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative.
The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether
to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees
for audit, audit-related and tax services.
The appendices to this Policy describe the audit, audit-related and tax services that have the general pre-approval of the
Audit Committee. The term of any general pre-approval is 12 months from the date of pre-approval, unless the Audit Committee
considers a different period and states otherwise. The Audit Committee will annually review and pre-approve the services that
may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit
Committee will add or subtract to the list of general pre-approved services from time to time, based on subsequent determinations.
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The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities.
It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by the independent auditor to
management.
Ernst & Young LLP, our independent auditor has reviewed this Policy and believes that implementation of the policy will
not adversely affect its independence.
II. Delegation
As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to
Stephen P. Smith, the Chairman of the Audit Committee. Mr. Smith must report, for informational purposes only, any pre-approval
decisions to the Audit Committee at its next scheduled meeting.
III. Audit Services
The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee.
Audit services include the annual financial statement audit (including required quarterly reviews), subsidiary audits and other
procedures required to be performed by the independent auditor to be able to form an opinion on the Partnership’s consolidated
financial statements. These other procedures include information systems and procedural reviews and testing performed in order
to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review.
Audit services also include the attestation engagement for the independent auditor’s report on internal controls for financial
reporting. The Audit Committee monitors the audit services engagement as necessary, but not less than on a quarterly basis, and
approves, if necessary, any changes in terms, conditions and fees resulting from changes in audit scope, partnership structure or
other items.
In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant
general pre-approval to other audit services, which are those services that only the independent auditor reasonably can provide.
Other audit services may include statutory audits or financial audits for our subsidiaries or our affiliates and services associated
with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection
with securities offerings.
IV. Audit-related Services
Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review
of the Partnership’s financial statements or that are traditionally performed by the independent auditor. Because the Audit Committee
believes that the provision of audit-related services does not impair the independence of the auditor and is consistent with the
SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related
services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accounting
consultations related to accounting, financial reporting or disclosure matters not classified as "Audit Services"; assistance with
understanding and implementing new accounting and financial reporting guidance from rulemaking authorities; financial audits
of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/or billing records required to
respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal control reporting
requirements.
V. Tax Services
The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance,
tax planning and tax advice without impairing the auditor’s independence, and the SEC has stated that the independent auditor
may provide such services. Hence, the Audit Committee believes it may grant general pre-approval to those tax services that have
historically been provided by the auditor, that the Audit Committee has reviewed and believes would not impair the independence
of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the
retention of the independent auditor in connection with a transaction initially recommended by the independent auditor, the sole
business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Internal Revenue
Code and related regulations. The Audit Committee will consult with the Chief Financial Officer or outside counsel to determine
that the tax planning and reporting positions are consistent with this Policy.
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VI. Pre-Approval Fee Levels or Budgeted Amounts
Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established
annually by the Audit Committee. Any proposed services exceeding these levels or amounts will require specific pre-approval by
the Audit Committee. The Audit Committee is mindful of the overall relationship of fees for audit and non-audit services in
determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determine the appropriate
ratio between the total amount of fees for audit, audit-related and tax services.
VII. Procedures
All requests or applications for services to be provided by the independent auditor that do not require specific approval by
the Audit Committee will be submitted to the Chief Financial Officer and must include a detailed description of the services to be
rendered. The Chief Financial Officer will determine whether such services are included within the list of services that have received
the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of any such services
rendered by the independent auditor.
Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the
Audit Committee by both the independent auditor and the Chief Financial Officer, and must include a joint statement as to whether,
in their view, the request or application is consistent with the SEC’s rules on auditor independence.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (2) Financial Statements and Schedules
See "Item 8. Financial Statements and Supplementary Data. "
(a)(3) Ciner Wyoming LLC Financial Statements
The financial statements of Ciner Wyoming LLC required pursuant to Rule 3-09 of Regulation S-X are included in this filing
as Exhibit 99.1.
(a)(4) Exhibits
Exhibit
Number
2.1
3.1
3.2
3.3
3.4
3.5
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
Description
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).
Fifth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of March
2, 2017 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on March 6, 2017).
Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011
(incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on December 16, 2011).
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).
Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17,
2002 (incorporated by reference to Exhibit 3.4 of Annual Report on Form 10-K for the year ended December 31,
2002).
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).
Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory
thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed June 23, 2003).
First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP
(Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report
on Form 8-K filed on July 20, 2005).
Second Amendment, dated as of March 28, 2007, to Note Purchase Agreement dated as of June 19, 2003 among
NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current
Report on Form 8-K filed on March 29, 2007).
First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the
purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on July
20, 2005).
Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and
the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on
March 29, 2007).
Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the
purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March
26, 2009).
Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the
purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April
21, 2011).
Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to
Exhibit 4.5 to Current Report on Form 8-K filed June 23, 2003).
Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed June 23, 2003).
Form of Series D Note (incorporated by reference to Exhibit 4.12 to Annual Report on Form 10-K filed February
28, 2007).
130
Table of Contents
Exhibit
Number
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25*
10.1
10.2
10.3
10.4
10.5
Description
Form of Series E Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed March 29,
2007).
Form of Series F Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 7,
2009).
Form of Series G Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 7,
2009).
Form of Series H Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 5,
2011).
Form of Series I Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 5,
2011).
Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 15,
2011).
Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on October
3, 2011).
Registration Rights Agreement, dated as of January 23, 2013, by and among Natural Resource Partners L.P. and the
Investors named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on January
25, 2013).
Third Amendment, dated as of June 16, 2015, to Note Purchase Agreements, dated as of June 19, 2003, among NRP
(Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form
8-K filed on June 18, 2015).
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).
Indenture, dated April 29, 2019, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as
issuers, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current
Report on Form 8-K filed on May 2, 2019).
Form of 9.125% Senior Notes due 2025 (contained in Exhibit 1 to Exhibit 4.21).
Registration Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P. and the
Purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March
6, 2017).
Form of Warrant to Purchase Common Units (incorporated by reference to Exhibit 4.1 to Current Report on Form
8-K filed on March 6, 2017).
Description of Equity Securities of Natural Resource Partners L.P.
Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC,
the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets
Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as
Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 18, 2015).
First Amendment, dated as of June 3, 2016, to Third Amended and Restated Credit Agreement, dated as of June 16,
2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and
Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint
Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report
on Form 8-K filed on June 7, 2016).
First Amended and Restated Omnibus Agreement, dated as of April 22, 2009, by and among Western Pocahontas
Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation,
Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners
L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed
May 7, 2009).
Limited Liability Company Agreement of Ciner Wyoming LLC, dated June 30, 2014 (incorporated by reference to
Exhibit 10.1 to Current Report on Form 8-K filed by Ciner Resources LP on July 2, 2014).
Amendment No. 1 to the Limited Liability Company Agreement of Ciner Wyoming LLC dated November 5, 2015
(incorporated by reference to Exhibit 10.22 to Annual Report on Form 10-K filed by Ciner Resources LP on March
11, 2016).
131
Table of Contents
Exhibit
Number
10.6
10.7
10.8
10.9
10.10+
10.11+
10.12+
10.13+*
10.14+*
10.15+*
21.1*
23.1*
23.2*
31.1*
31.2*
32.1**
32.2**
99.1*
Description
Second Amendment, dated as of March 2, 2017, to Third Amended and Restated Credit Agreement, dated as of June
16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent
and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and
Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.3 to Current
Report on Form 8-K filed on March 6, 2017).
Fourth Amendment, dated as of April 3, 2019, to Third Amended and Restated Credit Agreement, dated as of June
16, 2015, by and among NRP (Operating) LLC and the lenders party thereto (incorporated by reference to Exhibit
10.1 to Current Report on Form 8-K filed on April 9, 2019).
New Lender Agreement, dated as of April 8, 2019, by and among NRP (Operating) LLC and the lenders party thereto
(incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on April 9, 2019).
Board Representation and Observation Rights Agreement dated as of March 2, 2017, by and among Natural Resource
Partners L.P., Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, BTO Carbon
Holdings L.P. and the GoldenTree Purchasers named therein (incorporated by reference to Exhibit 10.2 to Current
Report on Form 8-K filed on March 6, 2017)
Natural Resource Partners L.P. 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to
Current Report on Form 8-K filed on January 17, 2018).
Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit
4.5 to Registration Statement on Form S-8 filed on February 9, 2018).
Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 4.6 to Registration
Statement on Form S-8 filed on February 9, 2018).
Form of Phantom Unit Award Agreement (Employees and Service Providers)
Form of Phantom Unit Award Agreement (Directors)
Form of Phantom Unit Award Agreement (Directors with Deferral Election)
List of Subsidiaries of Natural Resource Partners L.P.
Consent of Ernst & Young LLP.
Consent of Deloitte & Touche LLP.
Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
Financial Statements of Ciner Wyoming LLC as of December 31, 2019 and 2018 and for the years ended
December 31, 2019, 2018 and 2017.
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Labels Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
*
**
+
Filed herewith
Furnished herewith
Management compensatory plan or arrangement
132
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 27, 2020
Date: February 27, 2020
NATURAL RESOURCE PARTNERS L.P.
By: NRP (GP) LP, its general partner
By: GP NATURAL RESOURCE
PARTNERS LLC, its general partner
By:
/s/ CORBIN J. ROBERTSON, JR.
Corbin J. Robertson, Jr.
Chairman of the Board, Director and
Chief Executive Officer
(Principal Executive Officer)
By:
/s/ CHRISTOPHER J. ZOLAS
Christopher J. Zolas
Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer)
133
Table of Contents
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: February 27, 2020
Date: February 27, 2020
Date: February 27, 2020
Date: February 27, 2020
Date: February 27, 2020
Date: February 27, 2020
Date: February 27, 2020
Date: February 27, 2020
Date: February 27, 2020
/s/ GALDINO J. CLARO
Galdino J. Claro
Director
/s/ RUSSELL D. GORDY
Russell D. Gordy
Director
/s/ ALEXANDER D. GREENE
Alexander D. Greene
Director
/s/ S. REED MORIAN
S. Reed Morian
Director
/s/ PAUL B. MURPHY, JR.
Paul B. Murphy, Jr.
Director
/s/ RICHARD A. NAVARRE
Richard A. Navarre
Director
/s/ CORBIN J. ROBERTSON III
Corbin J. Robertson III
Director
/s/ STEPHEN P. SMITH
Stephen P. Smith
Director
/s/ LEO A. VECELLIO, JR.
Leo A. Vecellio, Jr.
Director
134
Exhibit 4.25
DESCRIPTION OF EQUITY SECURITIES OF NATURAL RESOURCE PARTNERS L.P.
Common Units
The common units represent limited partner interests in Natural Resource Partners L.P. that entitle the holders to participate
in our cash distributions and to exercise the rights or privileges available to limited partners under our partnership agreement.
For a description of the relative rights and preferences of holders of common units, preferred units and our general partner in
and to partnership distributions, see “—Cash Distributions.”
Our outstanding common units are listed on the New York Stock Exchange under the symbol “NRP.”
The transfer agent and registrar for our common units is American Stock Transfer & Trust Company.
Status as Limited Partner or Assignee
Except as described under “—The Partnership Agreement—Limited Liability,” the common units will be fully paid, and
the unitholders will not be required to make additional capital contributions to us.
Transfer of Common Units
Each purchaser of common units offered by this prospectus must execute a transfer application. By executing and
delivering a transfer application, the purchaser of common units:
•
•
•
•
•
becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted
limited partner;
automatically requests admission as a substituted limited partner in our partnership;
agrees to be bound by the terms and conditions of, and executes, our partnership agreement;
represents that he has the capacity, power and authority to enter into the partnership agreement;
grants powers of attorney to officers of the general partner and any liquidator of our partnership as specified in the
partnership agreement; and
• makes the consents and waivers contained in the partnership agreement.
An assignee will become a substituted limited partner of our partnership for the transferred units automatically upon the
recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and
records as soon as practicable following any transfer.
Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled
to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely
to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee
holder.
Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other
rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the
purchased common units. A purchaser of common units who does not execute and deliver a transfer application obtains only:
•
•
the right to assign the common unit to a purchaser or transferee; and
the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased
common units.
Thus, a purchaser of common units who does not execute and deliver a transfer application:
• will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or
“street name” account and the nominee or broker has executed and delivered a transfer application; and
• may not receive some federal income tax information or reports furnished to record holders of common units.
1
Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the
contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or
stock exchange regulations.
Class A Convertible Preferred Units
In March 2017, we issued 250,000 Class A Convertible Preferred Units (the “preferred units”) to certain entities controlled
by funds affiliated with The Blackstone Group, L.P. (collectively referred to as “Blackstone”) and certain affiliates of
GoldenTree Asset Management LP (collectively referred to as “GoldenTree”) (together the “Preferred Purchasers”) at a price of
$1,000 per preferred unit (the “Per Unit Purchase Price”). The preferred units represent limited partner interests in Natural
Resource Partners L.P. that entitle the holders to receive cumulative distributions at a rate of 12% per year, up to one half of
which we may pay in additional preferred units (such additional preferred units, the “PIK units”). The preferred units have a
perpetual term, unless converted or redeemed as described below. For a description of the relative rights and preferences of
holders of common units, preferred units and our general partner in and to partnership distributions, see “—Cash Distributions.”
Conversion
After March 2, 2022 and prior to March 2, 2025, the holders of the preferred units may elect to convert up to 33% of the
outstanding preferred units in any 12-month period into common units if the volume weighted average trading price of our common
units (the “VWAP”) for the 30 trading days immediately prior to date notice is provided is greater than $51.00. In such case, the
number of common units to be issued upon conversion would be equal to the Per Unit Purchase Price plus the value of any accrued
and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior
to the notice of conversion. Rather than have the preferred units convert to common units in accordance with the provisions of
this paragraph, NRP would have the option to elect to redeem the preferred units proposed to be converted for cash at a price equal
to Per Unit Purchase Price plus the value of any accrued and unpaid distributions.
On or after March 2, 2025, the holders of the preferred units may elect to convert the preferred units to common units at a
conversion rate equal to the Liquidation Value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days
immediately prior to the notice of conversion. The “Liquidation Value” will be an amount equal to the greater of: (1) (a) the Per
Unit Purchase Price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021, 1.70 and
(iii) on or after March 2, 2021, 1.85, less (b)(i) all Preferred Unit distributions previously made by NRP and (ii) all cash payments
previously made in respect of redemption of any PIK Units; and (2) the Per Unit Purchase Price plus the value of all accrued and
unpaid distributions.
To the extent the holders of the preferred units have not elected to convert their preferred units by March 2, 2029, we have
the right to force conversion of the preferred units into common units at a 10% discount to the VWAP for the 30 trading days
immediately prior to the notice of conversion.
Redemption
We have the ability to redeem at any time (subject to compliance with our debt agreements) all or any portion of the
preferred units (including PIK Units) for cash at the agreed upon per unit amount, which is calculated as the Per Unit Purchase
Price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021, 1.70 and (iii) on
or after March 2, 2021, 1.85.
Voting and Approval
The holders of the preferred units have the right to vote together with holders of NRP’s common units, as a single
class, on an as-converted basis and have other customary approval rights with respect to changes of the terms of the preferred
units. See “—The Partnership Agreement—Voting Rights.” In addition, Blackstone and GoldenTree have certain non-
transferrable approval rights over certain matters. See “—The Partnership Agreement—Special Approval Rights of Blackstone
and GoldenTree.”
2
The Partnership Agreement
The following is a summary of the material provisions of our partnership agreement. This summary does not purport to be
complete and is qualified in its entirety by reference to the provisions of applicable law and to our partnership agreement, which
is filed as an exhibit our Annual Report on Form 10-K.
Organization and Duration
Our partnership was formed on April 9, 2002 and will remain in existence until dissolved in accordance with our
partnership agreement.
Purpose
Our purpose under our partnership agreement is limited to serving as a member of the operating company and engaging in
any business activities that may be engaged in by the operating company or its subsidiaries or that are approved by our general
partner.
The limited liability company agreement of the operating company provides that the operating company may, directly or
indirectly, engage in:
•
•
its operations as conducted immediately before our initial public offering;
any other activity approved by our general partner but only to the extent that our general partner reasonably determines
that, as of the date of the acquisition or commencement of the activity, the activity generates “qualifying income” as
this term is defined in Section 7704 of the Internal Revenue Code; and
•
any activity that enhances the operations of an activity that is described in either of the preceding two clauses.
Our partnership agreement also permits us to engage directly in or enter into any form of corporation, partnership, joint
venture, limited liability company or other arrangement to engage in any business activity that is approved by our general
partner and that may be conducted lawfully by a Delaware limited partnership.
Notwithstanding the foregoing, our general partner does not have the authority to cause us to engage, directly or indirectly,
in any business activity that it reasonably determines would cause us to be treated as an association taxable as a corporation or
otherwise taxable as an entity for federal income tax purposes.
Our general partner is authorized in general to perform all acts deemed necessary to carry out our purposes and to conduct
our business.
Power of Attorney
Each limited partner and each person who acquires a unit from a unitholder and executes and delivers a transfer application
grants to our general partner (and, if appointed, a liquidator), a power of attorney to, among other things, execute and file
documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the
authority to amend, and to make consents and waivers under, and in accordance with, our partnership agreement.
Capital Contributions
Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited
Liability.”
Limited Liability
Participation in the Control of Our Partnership. Assuming that a limited partner does not participate in the control of our
business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that it
otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be
limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus his
share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited
partners as a group:
3
•
•
•
to remove or replace the general partner;
to approve some amendments to our partnership agreement; or
to take other action under our partnership agreement;
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could
be held personally liable for our obligations under Delaware law to the same extent as the general partner. This liability would
extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither
our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited
partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner
could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law.
Unlawful Partnership Distributions. Under the Delaware Act, a limited partnership may not make a distribution to a
partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their
partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would
exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a
limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors
is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds
the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of
the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the
amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a
limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except the assignee is
not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the
partnership agreement.
Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business. Our subsidiaries
currently conduct business in a number of states. Maintenance of limited liability for Natural Resource Partners, as the sole
member of the operating companies, may require compliance with legal requirements in the jurisdictions in which the operating
companies conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of members
for the obligations of a limited liability company have not been clearly established in many jurisdictions. If it were determined
that we were, by virtue of our member interests in the operating companies or otherwise, conducting business in any state
without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of
the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our
partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our
business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our
obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate
in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the
limited partners.
4
Voting Rights
The following matters require the unitholder vote specified below:
Issuance of additional units
Amendment of partnership
agreement
Except as described below under “—Special Approval Rights of
Blackstone and GoldenTree,” no approval right.
Certain amendments may be made by the general partner without the
approval of the unitholders. Other amendments generally require the
approval of a unit majority and/or a preferred unit majority. See “—
Amendment of the Partnership Agreement.”
Unit majority. See “—Merger, Sale or Other Disposition of Assets.”
Merger of our partnership or the
sale of all or substantially all of
our assets.
Amendment of the limited
liability company agreement and
other action taken by us as sole
member of the operating
company
Dissolution of our partnership
Reconstitution of our partnership
upon dissolution
Withdrawal of the general partner Our general partner may withdraw as general partner without approval
Unit majority if such amendment or other action would adversely
affect our limited partners (or any particular class of limited partners)
in any material respect. See “—Action Relating to Operating
Company.”
Unit majority. See “—Termination and Dissolution.”
Unit majority. See “—Termination and Dissolution”
e of additional units
Removal of the general partner
Transfer of the general partner
interest
Transfer of ownership interests in
the general partner
of our unitholders by giving 90 days’ written notice, and that
withdrawal will not constitute a violation of our partnership agreement.
See “—Withdrawal or Removal of the General Partner.”
Not less than 66 2/3% of the outstanding units, including units held by
our general partner and its affiliates; provided, however, that after the
eighth anniversary of March 2, 2017, the holders of preferred units (or
common units issued upon conversion thereof) may, if they hold 66
2/3% of the common units (or would, on conversion of all preferred
units), act by written consent to remove the general partner. See “—
Withdrawal or Removal of the General Partner.”
The general partner may transfer any or all of its general partner
interest without a vote of our unitholders. See “—Transfer of General
Partner Interest.
No approval required at any time. See “—Transfer of Ownership
Interests in the General Partner.”
Matters requiring the approval of a “unit majority” require the approval of a majority of the common units and preferred
units, on an as-converted basis, voting as a single class. For a description of the terms for conversion of the preferred units into
common units, see “—Class A Preferred Units—Conversion.” Except as otherwise described in our partnership agreement,
matters requiring the approval of a “preferred unit majority” require the approval of a majority of the preferred units, voting
separately as a class with one vote per preferred unit.
Special Approval Rights of Blackstone and GoldenTree
Blackstone has certain non-transferrable approval rights over certain matters, including:
•
the incurrence of new indebtedness or issuance of securities that rank senior to or pari passu with the preferred units,
subject to certain exceptions;
• material changes to NRP’s business;
•
•
•
•
acquisitions, divestitures and capital expenditures in excess of certain dollar thresholds;
amendments to material contracts resulting in a cash impact to NRP in excess of certain dollar thresholds;
settlement of any litigation or regulatory matter resulting in cash payments by NRP in excess of certain thresholds; and
amendments to related party contracts outside of the ordinary course of business.
5
In addition, GoldenTree has certain more limited approval rights, but will gain additional approval rights under certain
circumstances. The approval rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together
with its affiliates) or Golden Tree (together with its affiliates), as applicable, no longer own at least 20% of the total number of
preferred units issued on March 2, 2017, together with all PIK units that have been issued but not redeemed (the “Minimum
Preferred Unit Threshold”). To the extent any preferred units have converted into common units that are still held by Blackstone
(or its affiliates) or GoldenTree (or its affiliates), as applicable, such common units will be deemed to represent a number of
preferred units based on the weighted average number of common units issued in each conversion and will count towards the
Minimum Preferred Unit Threshold.
Issuance of Additional Securities
Except as described above under “—Special Approval Rights of Blackstone and GoldenTree,” our partnership agreement
authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the
consideration and on the terms and conditions established by our general partner in its sole discretion without the approval of
any limited partners.
It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities.
Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common
units in our distributions of available cash. In addition, the issuance of additional partnership common units or other equity
securities may dilute the value of the interests of the then-existing holders of common units in our net assets.
Except as described above under “—Special Approval Rights of Blackstone and GoldenTree,” in accordance with
Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, in the
sole discretion of our general partner, may have special voting rights to which the common units are not entitled.
Upon issuance of additional partnership securities, our general partner will have the right, which it may from time to time
assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same
terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to
maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units
that existed immediately prior to each issuance. The holders of common units do not have preemptive rights to acquire
additional common units or other partnership securities. Certain holders of preferred units have preemptive rights with respect
to the issuance of partnership securities, subject to certain exceptions, including the issuance of securities to the owners of
another entity in connection with the acquisition of such entity, the issuance of securities in an at-the-market offering program,
the issuance of securities in a firm commitment underwritten public offering in certain circumstances or the issuance of
securities pursuant to any plan or program authorized by our general partner or any dividend, split or other reclassification,
provided that with respect to any dividend, split or reclassification of parity securities, the preferred units are given ratable
treatment. The holders of the warrants shall have preemptive rights (proportional to their common unit ownership on an as
exercised basis) with respect to any issuance of common units and rights, options or warrants to purchase common units, and
convertible securities (other than PIK units) by NRP, subject to certain exceptions, including the issuance of securities to the
owners of another entity in connection with the acquisition of such entity, the issuance of securities in an at-the-market offering
program, the issuance of securities in a firm commitment underwritten public offering in certain circumstances or the issuance
of securities pursuant to any plan or program authorized by our general partner or any dividend, split or other reclassification.
Amendment of Partnership Agreement
General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner,
which consent may be given or withheld in its sole discretion. In order to adopt a proposed amendment, other than the
amendments discussed below, our general partner is required to seek written approval of the holders of the number of units
required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed
amendment. Except as described below, an amendment must be approved by a unit majority.
Prohibited Amendments. No amendment may be made that would:
•
enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or
class of limited partner interests so affected;
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•
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•
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enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts
distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent
of our general partner, which may be given or withheld in its sole discretion;
change the duration of our partnership;
provide that we are not dissolved upon an election to dissolve our partnership by our general partner that is approved
by a unit majority; or
give any person the right to dissolve our partnership other than our general partner’s right to dissolve our partnership
with the approval of a unit majority.
The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses
above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting together as a single
class (including units owned by the general partner and its affiliates).
No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the
approval of any limited partner or assignee to reflect:
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a change in our name, the location of our principal place of our business, our registered agent or our registered office;
the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
a change that, in the sole discretion of our general partner, is necessary or advisable for us to qualify or continue our
qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws
of any state or to ensure that neither we, the operating companies nor any of their subsidiaries will be treated as an
association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors,
officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of
1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement
Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied
or proposed;
an amendment that in the discretion of our general partner is necessary or advisable for the authorization of additional
partnership securities or rights to acquire partnership securities;
any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms
of our partnership agreement;
any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by us of, or
our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
a change in our fiscal year or taxable year and related changes;
a merger, conversion or conveyance effected in accordance with the partnership agreement; and
any other amendments substantially similar to any of the matters described in the clauses above.
In addition, our general partner may make amendments to our partnership agreement without the approval of any limited
partner or assignee if those amendments, in the discretion of our general partner:
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•
do not adversely affect the limited partners (including any particular class of limited partners as compared to other
classes of partnership interests) in any material respect;
are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive,
order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state
statute;
are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation,
guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for
trading, compliance with any of which our general partner deems to be in the best interests of us and our limited
partners;
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•
•
are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under
the provisions of our partnership agreement; or
are required to effect the intent expressed in the prospectus relating to our initial public offering or the intent of the
provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that
an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for
federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No
other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the
units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under
applicable law of any limited partner in our partnership.
Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding
units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected.
Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative
vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.
Actions Relating to Operating Company
Without the approval of a unit majority, our general partner is prohibited from consenting on our behalf as the sole member
of the operating company to any amendment to the limited liability company agreement of our operating company or taking any
action on our behalf permitted to be taken by a member of our operating company, in each case that would adversely affect our
limited partners (or any particular class of limited partners as compared to other classes of limited partners) in any material
respect.
Merger, Sale or Other Disposition of Assets
Our general partner is generally prohibited, without the prior approval of the holders of a unit majority, from causing us to,
among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series
of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale
exchange or other disposition of all or substantially all of the assets of our subsidiaries; provided that, except as described above
under “—Special Approval Rights of Blackstone and GoldenTree,” our general partner may mortgage, pledge, hypothecate or
grant a security interest in all or substantially all of our assets without that approval. Except as described above under “—
Special Approval Rights of Blackstone and GoldenTree,” our general partner may also sell all or substantially all our assets
under a foreclosure or other realization upon the encumbrances above without that approval.
If the conditions specified in the partnership agreement are satisfied, our general partner may merge our partnership or any
of its subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is
to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’
rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale
of all or substantially all of our assets or any other transaction or event.
Termination and Dissolution
We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
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the election of our general partner to dissolve us, if approved by the holders of a unit majority;
the sale, exchange or other disposition of all or substantially all of the assets and properties of our partnership and the
subsidiaries;
the entry of a decree of judicial dissolution of our partnership; or
the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner
other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or
withdrawal or removal following approval and admission of a successor.
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Upon a dissolution under the last clause above, a unit majority may also elect, within specific time limitations, to
reconstitute our partnership and continue its business on the same terms and conditions described in our partnership agreement
by forming a new limited partnership on terms identical to those in our partnership agreement and having as general partner an
entity approved by a unit majority, subject to our receipt of an opinion of counsel to the effect that:
•
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the action would not result in the loss of limited liability of any limited partner; and
neither our partnership, the reconstituted limited partnership, our operating company nor any of our other subsidiaries
would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax
purposes upon the exercise of that right to continue.
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to
wind up our affairs will, acting with all of the powers of our general partner that the liquidator deems necessary or desirable in
its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “—Cash Distributions—Distributions
of Cash upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or
distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.
Withdrawal or Removal of the General Partner
Our general partner may withdraw as general partner without first obtaining approval of our unitholders by giving 90 days’
written notice, and that withdrawal will not constitute a violation of our partnership agreement. At any time, the partners of our
general partner may sell or transfer all or part of their partnership interests in our general partner interests in our partnership
without the approval of the unitholders. See “—Transfer of General Partner Interest.”
Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general
partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units may select
a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding
limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after
that withdrawal, the holders of a majority of the outstanding common units agree in writing to continue the business of Natural
Resource Partners and to appoint a successor general partner. See “—Termination and Dissolution.”
Except as described below, our general partner may not be removed unless that removal is approved by the vote of the
holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general
partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our
general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the
outstanding common units. The ownership of more than 33 1/3% of the outstanding units by our general partner and its
affiliates would give them the practical ability to prevent our general partner’s removal.
After March 2, 2025, the holders of preferred units (or common units issued upon conversion thereof) may, if they hold 66
2/3% of the common units (or would, on conversion of all preferred units), act by written consent to remove the general partner
and provide for the election of a successor general partner.
Our partnership agreement also provides that if NRP (GP) LP is removed as our general partner under circumstances where
cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal, the general
partner will have the right to convert its general partner interest into common units or to receive cash in exchange for those
interests based on the fair market value of those interests at the time.
In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner
where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the
general partner interest of the departing general partner for a cash payment equal to the fair market value of that interest. Under
all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner
will have the option to require the successor general partner to purchase the general partner interest of the departing general
partner for fair market value. In each case, this fair market value will be determined by agreement between the departing
general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other
independent expert selected by the departing general partner and the successor general partner will determine the fair market
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value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen
by agreement of the experts selected by each of them will determine the fair market value.
If the above-described options are not exercised by either the departing general partner or the successor general partner, the
departing general partner’s general partner interest will automatically convert into common units equal to the fair market value
of that interest as determined by an investment banking firm or other independent expert selected in the manner described in the
preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due to the departing general
partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the
termination of any employees employed by the departing general partner or its affiliates for our benefit.
Transfer of General Partner Interest
Our general partner may transfer all or any part of its general partner interest without first obtaining approval of any
unitholder, and that transfer will not constitute a violation of our partnership agreement. As a condition of this transfer, the
transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of
the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.
Transfer of Ownership Interests in the General Partner
At any time, the partners of our general partner may sell or transfer all or part of their partnership interests in our general
partner without the approval of the unitholders.
Change of Management Provisions
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting
to remove NRP (GP) LP as our general partner or otherwise change our management. If any person or group other than our
general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses
voting rights on all of its units. This loss of voting rights does not apply to (i) any person or group that acquires the units from
our general partner or its affiliates, (ii) any transferees of that person or group approved by our general partner, (iii) any person
or group who acquires the units with the prior approval of the board of directors of our general partner, (iv) Blackstone or
GoldenTree (or their affiliates) and each of their respective transferees with respect to their ownership of preferred units, (v)
Blackstone or GoldenTree (or their affiliates) and each of their respective transferees with respect to their ownership of
common units issued upon conversion of preferred units, common units issued upon exercise of the warrants or common units
otherwise owned on the date of conversion or exercise, (vi) any holder of preferred units in connection with any vote, consent
or approval of the holders of the preferred units as a separate class or (vii) any group if the majority of units held by such group
are held by Blackstone or GoldenTree (or their respective affiliates) and each of their respective transferees of preferred units
with respect to their ownership common units issued upon conversion of preferred units, common units issued upon exercise of
the warrants or common units otherwise owned on the date of conversion or exercise.
Our partnership agreement also provides that if our general partner is removed under circumstances where cause does not
exist, our general partner will have the right to convert its general partner interest into common units or to receive cash in
exchange for those interests.
Limited Call Right
If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner
interests of any class, excluding preferred units, our general partner will have the right, which it may assign in whole or in part
to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class,
excluding preferred units, held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10
but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:
•
the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the
class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to
purchase those limited partner interests; and
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the current market price as of the date three days before the date the notice is mailed.
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As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner
interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder
of the exercise of this call right are the same as a sale by that unitholder of his common units in the market.
Meetings; Voting
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding,
unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings
of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an
assignee who is a record holder, but who has not yet been admitted as a limited partner, shall be voted by our general partner at
the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the
case of common units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the
votes on those common units in the same ratios as the votes of limited partners on other units are cast.
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a
meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary
to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders
owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person
or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been
called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by
holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.
Each record holder of a common unit or a preferred unit has one vote per unit, with the preferred units being voted on an
as-converted basis, although additional limited partner interests having special voting rights could be issued. See “—Issuance of
Additional Securities.” However, if at any time any person or group, other than (i) our general partner and its affiliates, (ii) a
direct or subsequently approved transferee of our general partner or its affiliates, (iii) a person or group who acquires the units
with the prior approval of the board of directors, (iv) Blackstone or GoldenTree (or their affiliates) and each of their respective
transferees with respect to their ownership of preferred units, (v) Blackstone or GoldenTree (or their affiliates) and each of their
respective transferees with respect to their ownership of common units issued upon conversion of preferred units, common
units issued upon exercise of the warrants or common units otherwise owned on the date of conversion or exercise, (vi) any
holder of preferred units in connection with any vote, consent or approval of the holders of the preferred units as a separate
class or (vii) any group if the majority of units held by such group are held by Blackstone or GoldenTree (or their respective
affiliates) and each of their respective transferees of preferred units with respect to their ownership common units issued upon
conversion of preferred units, common units issued upon exercise of the warrants or common units otherwise owned on the date
of conversion or exercise, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then
outstanding, the person or group will lose voting rights on all of its units and the units may not be voted on any matter and will
not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining
the presence of a quorum or for other similar purposes. Common units held in nominee or street name accounts will be voted by
the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the
beneficial owner and its nominee provides otherwise.
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of
common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
Status as Limited Partner or Assignee
Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be
required to make additional contributions.
An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a
substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and
distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to
common units owned by an assignee who has not become a substitute limited partner at the written direction of the assignee.
See “—Meetings; Voting.” Transferees who do not execute and deliver a transfer application will be treated neither as assignees
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nor as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports
furnished to holders of common units. See “—Common Units—Transfer of Common Units.”
Non-Citizen Assignees; Redemption
If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable
determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an
interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem, upon
30 days’ advance notice, the units held by the limited partner or assignee at their current market price. In order to avoid any
cancellation or forfeiture, our general partner may require each limited partner or assignee to furnish information about his
nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality,
citizenship or other related status within 30 days after a request for the information or our general partner determines after
receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be
treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted limited
partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind
upon our liquidation.
Indemnification
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent
permitted by law, from and against all losses, claims, damages or similar events:
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our general partner;
any departing general partner;
any person who is or was an affiliate of a general partner or any departing general partner;
any person who is or was a member, partner, officer, director, employee, agent or trustee of any of our subsidiaries, a
general partner or any departing general partner or any affiliate of any of our subsidiaries, a general partner or any
departing general partner; or
any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of
a general partner or any departing general partner as an officer, director, employee, member, partner, agent or trustee of
another person.
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees in its sole discretion,
our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable
us to effectuate indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses
incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities
under our partnership agreement.
Reimbursement of Expenses
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other necessary appropriate expenses allocable to us or otherwise reasonably incurred
by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation
and other amounts paid to persons who perform services for us or on our behalf and expenses allocated our general partner by
its affiliates. The general partner is entitled to determine expenses that are allocable to us in any reasonable manner determined
by our general partner in its sole discretion.
Books and Records
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be
maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal
year is the calendar year. We will furnish or make available to record holders of common units, within 120 days after the close
of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our
independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial
information within 90 days after the close of each quarter.
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We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days
after the close of each calendar year. This information is expected to be furnished in summary form so that some complex
calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will
depend on the cooperation of unitholders in supplying us with specific information.
Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his
federal and state income tax returns, regardless of whether he supplies us with information.
Right to Inspect Our Books and Records
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited
partner, upon reasonable demand and at his own expense, have furnished to him:
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a current list of the name and last known address of each partner;
a copy of our tax returns;
information as to the amount of cash, and a description and statement of the agreed value of any other property or
services, contributed or to be contributed by each partner and the date on which each became a partner;
copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and
powers of attorney under which they have been executed;
information regarding the status of our business and financial condition; and
any other information regarding our affairs as is just and reasonable.
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by
agreements with third parties to keep confidential.
Registration Rights
Under our partnership agreement, we have agreed to register for sale under the Securities Act of 1933 and applicable state
securities laws any common units or other partnership securities proposed to be sold by our general partner or any of its
affiliates if an exemption from the registration requirements is not otherwise available. These registration rights continue for
two years following any withdrawal or removal of our general partner. We have also agreed to include any partnership
securities held by our general partner or its affiliates in any registration statement that we file to offer partnership securities for
cash, except an offering relating solely to an employee benefit plan, for the same period. We are obligated to pay all expenses
incidental to the registration of common units for sale, excluding underwriting discounts and commissions.
Cash Distributions
Distributions of Available Cash
General. Within approximately 60 days after the end of each quarter, we will distribute all available cash to our general
partner and our unitholders of record on the applicable record date. First, we will make distributions on the preferred units at a
rate of 12% per year, up to one half of which we may make in PIK units. We will use all remaining available cash to pay
distributions to our general partner and our common unitholders pro rata.
Definition of Available Cash. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the
quarter:
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less the amount of cash reserves that the general partner determines in its reasonable discretion is necessary or
appropriate to:
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provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or
provide funds for distributions to our unitholders and to our general partner;
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•
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital
borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made
under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
The terms of the preferred units contain certain restrictions on our ability to pay distributions on our common units. To the
extent that either (i) our consolidated Leverage Ratio (as defined in our partnership agreement) is greater than 3.25x, or (ii) the
ratio of our Distributable Cash Flow (as defined in our partnership agreement) to cash distributions made or proposed to be
made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), we may not increase the
quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding preferred
units. In addition, if at any time after January 1, 2022, any PIK Units are outstanding, we may not make distributions on our
common units until we have redeemed all PIK Units for cash.
Distributions of Cash Upon Liquidation
If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process
called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any
remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
Manner of Adjustment for Gain. The manner of the adjustment is set forth in the partnership agreement. If our liquidation
occurs, we will allocate any gain to the partners in the following manner:
• First, to our general partner in the amount of certain prior loss allocations to the general partner; and
•
Second, to our general partner and our unitholders (other than holders of preferred units), pro rata.
Manner of Adjustment for Loss. The manner of the adjustment is set forth in the partnership agreement. If our liquidation
occurs, we will allocate any loss to the partners in the following manner:
• First, to our general partner and our unitholders (other than holders of preferred units) in proportion to the positive
balance in their capital accounts until the capital accounts of the general partner and the unitholders have been reduced
to zero without regard to any preferred units then held by the unitholders;
•
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Second, to our unitholders (other than holders of preferred units) to the extent of and in proportion to the positive
balances in their capital accounts;
Third, to the holders of our preferred units, to the extent of and in proportion to the positive balances in their capital
accounts; and
• Fourth, to our general partner.
Manner of Adjustment for Preferred Units. Notwithstanding the foregoing, the partnership agreement provides that if our
liquidation occurs and the per unit capital amount of each preferred unit does not equal or exceed the Liquidation Value (as
defined in the partnership agreement) after taking into account all other applicable adjustments, then items of income, gain, loss
and deduction shall be allocated (or reallocated, as necessary) among the general partner and the unitholders in a manner
determined appropriate by the general partner so as to cause, to the maximum extent possible, the per unit capital amount of
each preferred unit to equal the Liquidation Value. To the extent the Liquidation Value of a preferred unit exceeds the capital
account balance with respect to the preferred unit, the holder of the preferred unit will be entitled to a guaranteed payment in an
amount equal to such excess prior to the making of liquidating distributions.
Adjustments to Capital Accounts Upon the Issuance of Additional Units. We will make adjustments to capital accounts
upon the issuance of additional units. In doing so, we will allocate any gain or loss resulting from the adjustments to the
unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make
positive interim adjustments to the capital accounts, we will allocate any later negative adjustments to the capital accounts
resulting from the issuance of additional units or distributions of property or upon liquidation in a manner which results, to the
extent possible, in the capital account balance of the general partner equaling the amount which would have been in its capital
account if no earlier positive adjustments to the capital accounts had been made.
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Exhibit 10.13
Form of Phantom Unit Award Agreement
(Employees and Service Providers)
This Phantom Unit Award Agreement (this “Agreement”) is made and entered into as of
[ ] (the “Date of Grant”) by and between GP Natural Resource Partners LLC, a Delaware limited
liability company (“GP LLC”), and [ ] (“you” or “Service Provider”). Capitalized terms used but
not specifically defined herein shall have the meanings specified in the Natural Resource Partners
L.P. 2017 Long Term Incentive Plan (the “Plan”).
WHEREAS, Natural Resource Partners L.P., a Delaware limited partnership (the
“Partnership”), acting through the Board of Directors of GP LLC (the “Board”), the general partner
of NRP (GP) LP, a Delaware limited partnership, the general partner of the Partnership (the “General
Partner”), GP LLC has adopted the Plan under which GP LLC is authorized to grant Phantom Units
to certain Service Providers of the Partnership;
WHEREAS, the Partnership, in order to induce you to enter into and to continue to dedicate
service to the Partnership and to materially contribute to the success of the Partnership, agrees to
grant you the Phantom Unit Award;
WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of
this Agreement as if fully set forth herein; and
WHEREAS, you desire to accept the Phantom Unit Award made pursuant to this Agreement.
NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for
other valuable consideration hereinafter set forth, the parties agree as follows:
1.
The Grant. Subject to the conditions set forth below, the Partnership hereby grants
you effective as of the Date of Grant, as a matter of separate inducement but not in lieu of any salary
or other compensation for your services to the Partnership, an Award consisting of [ ] Phantom
Units (the “Phantom Unit Award”) in accordance with the terms and conditions set forth in this
Agreement and the Plan, whereby each Phantom Unit represents the right to receive one Unit on
the date the Forfeiture Restrictions expire with respect to such Phantom Unit.
2.
Phantom Unit Account. The Partnership shall establish and maintain a bookkeeping
account on its records for you (a “Phantom Unit Account”) and shall record in such Phantom Unit
Account: (a) the number of Phantom Units granted to you, (b) the amount deliverable to you at
settlement on account of Phantom Units that have vested and (c) the amount of any distribution
equivalent rights credited to you in accordance with Section 5 hereof. You shall not have any interest
in any fund or specific assets of the Partnership by reason of this Award or the Phantom Unit Account
established for you.
3.
Rights of Service Provider. No Units shall be issued to you at the time the grant is
made, and you shall not be, nor have any of the rights and privileges of, a unitholder or limited
partner of the Partnership with respect to any Phantom Units recorded in the Phantom Unit Account.
You shall have no voting rights with respect to the Phantom Units.
1
4.
Vesting of Phantom Units. The Phantom Units are restricted in that they may be
forfeited by the Service Provider and in that they may not, except as otherwise provided in the Plan,
be transferred or otherwise disposed of by the Service Provider. Subject to the terms and conditions
of this Agreement, the restrictions with respect to the Phantom Unit Award (including any associated
DERs) will expire and such Phantom Units will become vested and nonforfeitable as set forth on
Schedule I hereto; provided, however, that the restrictions will expire on such date(s) only if your
service relationship with GP LLC, the General Partner, the Partnership, or any of the Partnership’s
subsidiaries (collectively, the “Partnership Group”) continues from the Date of Grant through the
applicable vesting date.
5.
Distribution Equivalent Rights. The Partnership hereby grants to you rights to
dividend equivalents with respect to the Phantom Units granted pursuant to this Agreement
(“DERs”). The DERs awarded to you under this Section 5 shall entitle you to the payment, with
respect to each Unit that is subject to a Phantom Unit granted pursuant to this Agreement that has
not been cancelled or forfeited, of an amount in cash equal to the amount of any cash dividend or
Unit distribution paid by the GP LLC with respect to one Unit while such Phantom Unit remains
outstanding. Such amount shall be subject to the same vesting schedule as the Phantom Unit to
which it relates and shall be paid to you in cash on the date that the Phantom Unit to which it relates
is settled in accordance with Section 8 hereof. No interest shall be payable or otherwise owed with
respect to such DERs for the period of time beginning on the date a distribution is paid to the
Partnership’s unitholders and ending on the date the DERs are paid to you pursuant to this Agreement.
Any DERs which relate to a Phantom Unit that do not become vested shall be forfeited at the same
time the related Phantom Unit is forfeited.
6.
Terminations of Services. Except as otherwise provided in Sections 6(a), (b), (c),
and (d) below, if your service relationship with the Partnership Group is terminated for any reason,
then the portion of the Phantom Unit Award (and any associated DERs) for which the Forfeiture
Restrictions have not lapsed as of the date of termination shall become null and void and such
Phantom Units shall be forfeited. The portion of the Phantom Unit Award for which the Forfeiture
Restrictions have lapsed as of the date of such termination shall not be forfeited.
a.
Death or Disability. If your service relationship with the Partnership Group
is terminated due to your death or Disability, then the Forfeiture Restrictions on the Phantom Unit
Award shall immediately lapse, and the Phantom Unit Award will be fully vested as of such
termination. For purposes of this Phantom Unit Award, “Disability” shall have the meaning given
such term in any employment agreement between you and the Partnership or its Affiliates. Provided,
however, that if there is no existing employment agreement between you and the Partnership or its
Affiliates, the term “Disability” shall mean that you are unable to engage in substantial gainful
activity by reason of any medically determinable physical or mental impairment that can be expected
to result in death or can be expected to last for a continuous period of not less than 12 months.
b.
Change of Control. In the event of a Change of Control, the Forfeiture
Restrictions on the Phantom Unit Award shall immediately lapse, and the Phantom Unit Award will
be fully vested as of the date of such Change of Control.
2
c.
Termination of Service Provider Without Cause. If your service relationship
with the Partnership Group is terminated by the Partnership or any of its Affiliates for any reason
other than for Cause, then the Forfeiture Restrictions on the Phantom Unit Award shall immediately
lapse, and the Phantom Unit Award will be fully vested as of such termination. “Cause” means one
or more of the following events: (i) a Service Provider’s continued failure, after written notice is
given and a reasonable opportunity to cure has been granted, to comply with the reasonable written
directives of the Partnership or any of its Affiliates, (ii) a Service Provider’s failure to comply in
any material respect with the written terms of employment with the Partnership or any of its
Affiliates, (iii) a Service Provider’s willful misconduct resulting in material and demonstrable
damage to the Partnership or any of its Affiliates, including, without limitation, theft, embezzlement
or material misrepresentations or concealments on any written reports submitted to such the
Partnership or any of its Affiliates, (iv) Service Provider’s conviction of, or plea of nolo contendere
to, any felony or to any crime or offense involving acts of theft, fraud, embezzlement or similar
conduct or (v) Service Provider’s material breach of written policies of the Partnership or any of
its Affiliates concerning employee discrimination or harassment, after written notice is given and
a reasonable opportunity to cure been granted, if such breach is capable of being cured without
penalty or damages to the Partnership or any of its Affiliates.
d.
Termination by Service Provider for Good Reason. If your service
relationship with the Partnership Group is terminated due to Good Reason, then the Forfeiture
Restrictions on the Phantom Unit Award shall immediately lapse, and the Phantom Unit Award will
be fully vested as of such termination. “Good Reason” means the occurrence, without the Service
Provider’s express written consent of (i) a reduction in Service Provider’s then current annual base
salary of 10% or more; or (ii) a material diminution in Service Provider’s authority, duties or
responsibilities (other than a mere change in the person or persons to whom Service Provider reports);
provided, however, that Service Provider must give written notice to the Partnership Group of the
existence of such a condition described in (i) or (ii) above within ninety (90) days of the initial
existence of the condition, and the Partnership Group shall have thirty (30) days from the date when
such notice is provided to cure the condition (if such condition can be cured) without being required
to accelerate vesting for unvested awards due to termination of employment. To the extent that
notice is provided in accordance with the foregoing sentence and the condition is not cured within
the 30-day period, then Service Provider must actually terminate such Service Provider’s
relationship with the Partnership Group within six (6) months of the initial occurrence of any of
the conditions above for such termination to qualify as Good Reason.
7.
Leave of Absence. With respect to the Phantom Unit Award, the Partnership may,
in its sole discretion, determine that if you are on a leave of absence for any reason, you will be
considered to still be a Service Provider to the Partnership Group; provided, that rights to the
Phantom Unit Award during a leave of absence will be limited to the extent to which those rights
were earned or vested when the leave of absence began.
8.
Settlement Date; Manner of Settlement. Promptly following the expiration of the
Forfeiture Restrictions and upon receipt by the Partnership of any tax withholding as may be required
pursuant to Section 9, but in no event later than the first March 15 following the date the Forfeiture
Restrictions expire with respect to a Phantom Unit, the Partnership shall deliver to you the number
3
of Units equal to the number of Phantom Units granted to you hereunder as to which the Forfeiture
Restrictions have lapsed. In addition, the Partnership shall deliver to you an amount of cash equal
to the DERs that relate to the Phantom Units as to which the Forfeiture Restrictions have lapsed.
The amounts deliverable pursuant to this Section 8 shall not bear any interest owing to the passage
of time.
9.
Payment of Taxes. The Partnership may require you to pay to the Partnership (or a
Partnership Affiliate if you are a Service Provider to a Partnership Affiliate) an amount the
Partnership deems necessary to satisfy its (or its Affiliate’s) current or future obligation to withhold
federal, state or local income or other taxes that you incur as a result of the Phantom Unit Award.
With respect to any required tax withholding, the Partnership (or its Affiliate) may withhold from
the amount deliverable to you under this Agreement the amount necessary or appropriate to satisfy
the Partnership’s (or its Affiliate’s) obligation to withhold taxes.
10.
Clawback. Notwithstanding any provisions in the Plan or this Agreement to the
contrary, any portion of the payments and benefits provided under this Agreement shall be subject
to any clawback policy adopted by GP LLC, including any such policy adopted to conform to the
Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated
thereunder by the Securities and Exchange Commission, and including any such clawback policies
adopted with retroactive effect.
11.
Right of the Partnership and its Affiliates to Terminate Services. Nothing in this
Agreement confers upon you the right to continue as a Service Provider to the Partnership Group,
or interfere in any way with the rights of any member of the Partnership Group to terminate your
service relationship at any time.
12.
Furnish Information. You agree to furnish to the Partnership all information
requested by the Partnership to enable it to comply with any reporting or other requirements imposed
upon the Partnership by or under any applicable statute or regulation.
13.
No Liability for Good Faith Determinations. The Partnership and the members of
the Board shall not be liable for any act, omission or determination taken or made in good faith
with respect to this Agreement or the Phantom Unit Award.
14.
Executions of Receipts and Releases. Any payment of cash or other property to you,
or to your legal representative, heir, legatee or distributee in accordance with the provisions hereof,
shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The
Partnership may require you or your legal representative, heir, legatee or distributee, as a condition
precedent to such payment or issuance, to execute a release and receipt therefor in such form as it
shall determine.
15.
No Guarantee of Interests. The Board and the Partnership do not guarantee the
Phantom Units from loss or depreciation.
16.
Partnership Records. Records of the Partnership or its Affiliates regarding your
period of service, termination of service and the reason(s) therefor, leaves of absence, re-
4
employment, and other matters shall be conclusive for all purposes hereunder, unless determined
by the Partnership to be incorrect.
17.
Notice. All notices required or permitted under this Agreement must be in writing
and personally delivered or sent by mail and shall be deemed to be delivered on the date on which
it is actually received by the Person to whom it is properly addressed or if earlier, the date it is sent
via certified United States mail or reputable overnight delivery service (charges prepaid).
18. Waiver of Notice. Any Person entitled to notice hereunder may waive such notice in
writing.
19.
Successors. The Partnership may assign any of its rights under this Agreement
without your consent. This Agreement shall be binding upon and inure to the benefit of the successors
and assigns of GP LLC, the General Partner and the Partnership. Subject to the restrictions on
transfer set forth herein and in the Plan, this Agreement and the Forfeiture Restrictions shall be
binding upon and enforceable against you and your beneficiaries, executors, administrators and the
person(s) to whom the Phantom Unit Award may be transferred by will or the laws of descent or
distribution.
20.
Tax Consultation. Service Provider acknowledges and agrees that (a) Service
Provider is not relying upon any determination by GP LLC, the General Partner, the Partnership,
any of their respective Affiliates, or any of their respective employees, directors, officers, attorneys,
or agents (collectively, the “Partnership Parties”) of the Fair Market Value of the Units on the Date
of Grant, (b) Service Provider is not relying upon any written or oral statement or representation
of the Partnership Parties regarding the tax effects associated with your execution of the Agreement
and his or her receipt, holding and vesting of the Phantom Unit Award, and (c) in deciding to enter
into this Agreement, Service Provider is relying on his or her own judgment and the judgment of
the professionals of Service Provider’s choice with whom he or she has consulted. Service Provider
hereby releases, acquits and forever discharges the Partnership Parties from all actions, causes of
actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any
nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the
tax effects associated with Service Provider’s execution of the Agreement and his or her receipt,
holding and exercise of the Phantom Unit Award.
21.
Severability. If any provision of this Agreement is held to be illegal or invalid for
any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such
provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal
or invalid provision had never been included herein.
22.
Partnership or Committee Action. Any action required of GP LLC, the Partnership
or the General Partner shall be by resolution of the Board or Committee or by a Person or entity
authorized to act by resolution of the Board or Committee.
23.
Headings. The titles and headings of Sections are included for convenience of
reference only and are not to be considered in construction of the provisions hereof.
5
24.
Governing Law. All questions arising with respect to the provisions of this
Agreement shall be determined by application of the laws of the State of Delaware, without giving
any effect to any conflict of law provisions thereof, except to the extent Delaware state law is
preempted by federal law.
25.
Consent to Electronic Delivery; Electronic Signature. In lieu of receiving documents
in paper format, the Service Provider hereby consents to receive documents from the Partnership,
GP LLC, the General Partner, and any plan administrator by means of electronic delivery, provided
that such delivery complies with the rules, regulations and guidance issued by the Securities and
Exchange Commission and any other applicable government agency. This consent shall be effective
for the entire time that the Service Provider is a participant in the Plan.
26.
Consent to Jurisdiction and Venue. You hereby consent and agree that state courts
located in Harris County, Texas and the United States District Court for the Southern District of
Texas each shall have personal jurisdiction and proper venue with respect to any dispute between
you and the Partnership (or its Affiliate) arising in connection with the Phantom Unit Award or this
Agreement. In any dispute with the Partnership (or its Affiliate), you will not raise, and you hereby
expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.
27.
Amendment. This Agreement may be amended by the Board or by the Committee
at any time in a manner consistent with Section 7(a) of the Plan.
28.
Terms of Agreement. This Agreement is subject to all the terms, conditions,
limitations and restrictions contained in this Agreement and the Plan. Except as provided in Section
6 of this Agreement, together, the Agreement and Plan constitute the entire agreement of the parties
with regard to the subject matter hereof, and contain all the covenants, promises, representations,
warranties and agreements between the parties with respect to the Phantom Units granted hereby.
Without limiting the scope of the preceding sentence, all prior understandings and agreements, if
any, among the parties hereto relating to the subject matter hereof are hereby null and void and of
no further force and effect.
6
IN WITNESS HEREOF, GP LLC has caused this Agreement to be executed by its
officer thereto duly authorized, and Service Provider has set his or her hand as to the date
and year first written above.
GP Natural Resource Partners LLC,
a Delaware limited liability company
By:
Name:
Title:
[SERVICE PROVIDER NAME]
7
SCHEDULE I
Vesting Date
Number of Phantom Units
8
Exhibit 10.14
Form of Phantom Unit Award Agreement
(Non-Employee Director without Deferral Election)
This Phantom Unit Award Agreement (this “Agreement”) is made and entered into as of
[ ] (the “Date of Grant”) by and between GP Natural Resource Partners LLC, a Delaware limited
liability company (“GP LLC”), and [ ] (“you” or “Service Provider”). Capitalized terms used but
not specifically defined herein shall have the meanings specified in the Natural Resource Partners
L.P. 2017 Long Term Incentive Plan (the “Plan”).
WHEREAS, Natural Resource Partners L.P., a Delaware limited partnership (the
“Partnership”), acting through the Board of Directors of GP LLC (the “Board”), the general partner
of NRP (GP) LP, a Delaware limited partnership, the general partner of the Partnership (the “General
Partner”), GP LLC has adopted the Plan under which GP LLC is authorized to grant Phantom Units
to certain Service Providers of the Partnership;
WHEREAS, the Partnership, in order to induce you to enter into and to continue to dedicate
service to the Partnership and to materially contribute to the success of the Partnership, agrees to
grant you the Phantom Unit Award;
WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of
this Agreement as if fully set forth herein; and
WHEREAS, you desire to accept the Phantom Unit Award made pursuant to this Agreement.
NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for
other valuable consideration hereinafter set forth, the parties agree as follows:
1.
The Grant. Subject to the conditions set forth below, the Partnership hereby grants
you effective as of the Date of Grant, as a matter of separate inducement but not in lieu of any salary
or other compensation for your services to the Partnership, an Award consisting of [ ] Phantom
Units (the “Phantom Unit Award”) in accordance with the terms and conditions set forth in this
Agreement and the Plan, whereby each Phantom Unit represents the right to receive one Unit on
the date the Forfeiture Restrictions expire with respect to such Phantom Unit.
2.
Phantom Unit Account. The Partnership shall establish and maintain a bookkeeping
account on its records for you (a “Phantom Unit Account”) and shall record in such Phantom Unit
Account: (a) the number of Phantom Units granted to you, (b) the amount deliverable to you at
settlement, and (c) the amount of any distribution equivalent rights credited to you in accordance
with Section 5 hereof. You shall not have any interest in any fund or specific assets of the Partnership
by reason of this Award or the Phantom Unit Account established for you.
3.
Rights of Service Provider. No Units shall be issued to you at the time the grant is
made, and you shall not be, nor have any of the rights and privileges of, a unitholder or limited
partner of the Partnership with respect to any Phantom Units recorded in the Phantom Unit Account.
You shall have no voting rights with respect to the Phantom Units.
4.
Vesting and Transferability. The Phantom Units are restricted in that they may be
forfeited by the Service Provider and in that they may not, except as otherwise provided in the Plan,
be transferred or otherwise disposed of by the Service Provider. Subject to the terms and conditions
of this Agreement, the restrictions with respect to the Phantom Unit Award (including any associated
DERs) will expire and such Phantom Units will become vested and nonforfeitable on the one year
anniversary of the Date of Grant; provided, however, that the restrictions will expire on such date
only if you remain a member of the Board continuously from the Date of Grant through the vesting
date.
5.
Distribution Equivalent Rights. The Partnership hereby grants to you rights to
dividend equivalents with respect to the Phantom Units granted pursuant to this Agreement
(“DERs”). The DERs awarded to you under this Section 5 shall entitle you to the payment, with
respect to each Unit that is subject to a Phantom Unit granted pursuant to this Agreement, of an
amount in cash equal to the amount of any cash dividend or Unit distribution paid by the GP LLC
with respect to one Unit while such Phantom Unit remains outstanding. Such amount shall be
subject to the same vesting schedule as the Phantom Unit to which it relates and shall be paid to
you in cash on the date that the Phantom Unit to which it relates is settled in accordance with Section
8 hereof. No interest shall be payable or otherwise owed with respect to such DERs for the period
of time beginning on the date a distribution is paid to the Partnership’s unitholders and ending on
the date the DERs are paid to you pursuant to this Agreement.
6.
Termination of Board Service. If your service as a member of the Board terminates
for any reason, then the portion of the Phantom Unit Award (and any associated DERs) for which
the Forfeiture Restrictions have not lapsed as of the date of termination shall become null and void
and such Phantom Units shall be forfeited.
7.
Leave of Absence. With respect to the Phantom Unit Award, the Partnership may,
in its sole discretion, determine that if you are on a leave of absence for any reason, you will be
considered to still be a Service Provider to the Partnership Group; provided, that rights to the
Phantom Unit Award during a leave of absence will be limited to the extent to which those rights
were earned or vested when the leave of absence began.
8.
Settlement Date; Manner of Settlement. Promptly following the expiration of the
Forfeiture Restrictions, but in no event later than the first March 15 following the date the Forfeiture
Restrictions expire with respect to a Phantom Unit, the Partnership shall deliver to you the number
of Units equal to the number of Phantom Units granted to you hereunder as to which the Forfeiture
Restrictions have lapsed. In addition, the Partnership shall deliver to you an amount of cash equal
to the DERs that relate to the Phantom Units as to which the Forfeiture Restrictions have lapsed.
The amounts deliverable pursuant to this Section 8 shall not bear any interest owing to the passage
of time.
9.
Right of the Partnership and its Affiliates to Terminate Services. Nothing in this
Agreement confers upon you the right to continue as a Service Provider for the Partnership or its
Affiliates, or interfere in any way with the rights of the Partnership or its Affiliates to terminate
your service relationship at any time.
2
10.
Furnish Information. You agree to furnish to the Partnership all information
requested by the Partnership to enable it to comply with any reporting or other requirements imposed
upon the Partnership by or under any applicable statute or regulation.
11.
No Liability for Good Faith Determinations. The Partnership and the members of
the Board shall not be liable for any act, omission or determination taken or made in good faith
with respect to this Agreement or the Phantom Unit Award.
12.
Executions of Receipts and Releases. Any payment of cash or other property to you,
or to your legal representative, heir, legatee or distributee in accordance with the provisions hereof,
shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The
Partnership may require you or your legal representative, heir, legatee or distributee, as a condition
precedent to such payment or issuance, to execute a release and receipt therefor in such form as it
shall determine.
13.
No Guarantee of Interests. The Board and the Partnership do not guarantee the
Phantom Units from loss or depreciation.
14.
Partnership Records. Records of the Partnership or its Affiliates regarding your
period of service, termination of service and the reason(s) therefor, leaves of absence, re-
employment, and other matters shall be conclusive for all purposes hereunder, unless determined
by the Partnership to be incorrect.
15.
Notice. All notices required or permitted under this Agreement must be in writing
and personally delivered or sent by mail and shall be deemed to be delivered on the date on which
it is actually received by the Person to whom it is properly addressed or if earlier, the date it is sent
via certified United States mail or reputable overnight delivery service (charges prepaid).
16. Waiver of Notice. Any Person entitled to notice hereunder may waive such notice
in writing.
17.
Successors. The Partnership may assign any of its rights under this Agreement
without your consent. This Agreement shall be binding upon and inure to the benefit of the successors
and assigns of GP LLC, the General Partner and the Partnership. Subject to the restrictions on
transfer set forth herein and in the Plan, this Agreement shall be binding upon and enforceable
against you and your beneficiaries, executors, administrators and the person(s) to whom the Phantom
Unit Award may be transferred by will or the laws of descent or distribution.
18.
Tax Consultation. Service Provider acknowledges and agrees that (a) Service
Provider is not relying upon any determination by GP LLC, the General Partner, the Partnership,
any of their respective Affiliates, or any of their respective employees, directors, officers, attorneys,
or agents (collectively, the “Partnership Parties”) of the Fair Market Value of the Units on the Date
of Grant, (b) Service Provider is not relying upon any written or oral statement or representation
of the Partnership Parties regarding the tax effects associated with your execution of the Agreement
and his or her receipt, holding and vesting of the Phantom Unit Award, and (c) in deciding to enter
into this Agreement, Service Provider is relying on his or her own judgment and the judgment of
3
the professionals of Service Provider’s choice with whom he or she has consulted. Service Provider
hereby releases, acquits and forever discharges the Partnership Parties from all actions, causes of
actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any
nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the
tax effects associated with Service Provider’s execution of the Agreement and his or her receipt,
holding and exercise of the Phantom Unit Award.
19.
Severability. If any provision of this Agreement is held to be illegal or invalid for
any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such
provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal
or invalid provision had never been included herein.
20.
Partnership or Committee Action. Any action required of GP LLC, the Partnership
or the General Partner shall be by resolution of the Board or Committee or by a Person or entity
authorized to act by resolution of the Board or Committee.
21.
Headings. The titles and headings of Sections are included for convenience of
reference only and are not to be considered in construction of the provisions hereof.
22.
Governing Law. All questions arising with respect to the provisions of this
Agreement shall be determined by application of the laws of the State of Delaware, without giving
any effect to any conflict of law provisions thereof, except to the extent Delaware state law is
preempted by federal law.
23.
Consent to Electronic Delivery; Electronic Signature. In lieu of receiving documents
in paper format, the Service Provider hereby consents to receive documents from the Partnership,
GP LLC, the General Partner, and any plan administrator by means of electronic delivery, provided
that such delivery complies with the rules, regulations and guidance issued by the Securities and
Exchange Commission and any other applicable government agency. This consent shall be effective
for the entire time that the Service Provider is a participant in the Plan.
24.
Consent to Jurisdiction and Venue. You hereby consent and agree that state courts
located in Harris County, Texas and the United States District Court for the Southern District of
Texas each shall have personal jurisdiction and proper venue with respect to any dispute between
you and the Partnership (or its Affiliate) arising in connection with the Phantom Unit Award or this
Agreement. In any dispute with the Partnership (or its Affiliate), you will not raise, and you hereby
expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.
25.
Amendment. This Agreement may be amended by the Board or by the Committee
at any time in a manner consistent with Section 7(a) of the Plan.
26.
Terms of Agreement. This Agreement is subject to all the terms, conditions,
limitations and restrictions contained in this Agreement and the Plan. Together, this Agreement and
the Plan constitute the entire agreement of the parties with regard to the subject matter hereof, and
contain all the covenants, promises, representations, warranties and agreements between the parties
with respect to the Phantom Units granted hereby. Without limiting the scope of the preceding
4
sentence, all prior understandings and agreements, if any, among the parties hereto relating to the
subject matter hereof are hereby null and void and of no further force and effect.
5
IN WITNESS HEREOF, GP LLC has caused this Agreement to be executed by its
officer thereto duly authorized, and Service Provider has set his or her hand as to the date
and year first written above.
GP Natural Resource Partners LLC,
a Delaware limited liability company
By:
Name:
Title:
[NON-EMPLOYEE DIRECTOR]
6
Exhibit 10.15
Form of Phantom Unit Award Agreement
(Non-Employee Director with Deferral)
This Phantom Unit Award Agreement (this “Agreement”) is made and entered into as of
[ ] (the “Date of Grant”) by and between GP Natural Resource Partners LLC, a Delaware limited
liability company (“GP LLC”), and [ ] (“you” or “Service Provider”). Capitalized terms used but
not specifically defined herein shall have the meanings specified in the Natural Resource Partners
L.P. 2017 Long Term Incentive Plan (the “Plan”).
WHEREAS, Natural Resource Partners L.P., a Delaware limited partnership (the
“Partnership”), acting through the Board of Directors of GP LLC (the “Board”), the general partner
of NRP (GP) LP, a Delaware limited partnership, the general partner of the Partnership (the “General
Partner”), GP LLC has adopted the Plan under which GP LLC is authorized to grant Phantom Units
to certain Service Providers of the Partnership;
WHEREAS, the Partnership, in order to induce you to enter into and to continue to dedicate
service to the Partnership and to materially contribute to the success of the Partnership, agrees to
grant you the Phantom Unit Award;
WHEREAS, a copy of the Plan has been furnished to you and shall be deemed a part of
this Agreement as if fully set forth herein; and
WHEREAS, pursuant to that certain Natural Resource Partners L.P. 2017 Director Time
of Settlement Election Form entered into between GP LLC and Service Provider, effective as of
December 29, 2017 (the “Deferral Election Form”), the Service Provider has elected to receive
this Phantom Unit Award; and
WHEREAS, you desire to accept the Phantom Unit Award made pursuant to this Agreement.
NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for
other valuable consideration hereinafter set forth, the parties agree as follows:
1.
The Grant. Subject to the conditions set forth below, the Partnership hereby grants
you effective as of the Date of Grant, as a matter of separate inducement but not in lieu of any salary
or other compensation for your services to the Partnership, an Award consisting of [ ] Phantom
Units (the “Phantom Unit Award”) in accordance with the terms and conditions set forth in this
Agreement and the Plan, whereby each Phantom Unit represents the right to receive one Unit on
the date the deferral period, as contained in the Deferral Election Form (the “Deferral Period”)
ends with respect to such Phantom Unit.
2.
Phantom Unit Account. The Partnership shall establish and maintain a bookkeeping
account on its records for you (a “Phantom Unit Account”) and shall record in such Phantom Unit
Account: (a) the number of Phantom Units granted to you, (b) the amount deliverable to you at
settlement, and (c) the amount of any distribution equivalent rights credited to you in accordance
with Section 5 hereof. You shall not have any interest in any fund or specific assets of the Partnership
by reason of this Award or the Phantom Unit Account established for you.
1
3.
Rights of Service Provider. No Units shall be issued to you at the time the grant is
made, and you shall not be, nor have any of the rights and privileges of, a unitholder or limited
partner of the Partnership with respect to any Phantom Units recorded in the Phantom Unit Account.
You shall have no voting rights with respect to the Phantom Units.
4.
Vesting and Transferability. The Phantom Units are restricted in that they may be
forfeited by the Service Provider and in that they may not, except as otherwise provided in the Plan,
be transferred or otherwise disposed of by the Service Provider. Subject to the terms and conditions
of this Agreement, the restrictions with respect to the Phantom Unit Award (including any associated
DERs) will expire and such Phantom Units will become vested and nonforfeitable on the one year
anniversary of the Date of Grant; provided, however, that the restrictions will expire on such date
only if you remain a member of the Board continuously from the Date of Grant through the vesting
date.
5.
Distribution Equivalent Rights. The Partnership hereby grants to you rights to
dividend equivalents with respect to the Phantom Units granted pursuant to this Agreement
(“DERs”). The DERs awarded to you under this Section 5 shall entitle you to the payment, with
respect to each Unit that is subject to a Phantom Unit granted pursuant to this Agreement, of an
amount in cash equal to the amount of any cash dividend or Unit distribution paid by the GP LLC
with respect to one Unit while such Phantom Unit remains outstanding. . Such amount shall be
subject to the same vesting schedule as the Phantom Unit to which it relates and shall be paid to
you in cash on the date that the Phantom Unit to which it relates is settled in accordance with Section
8 hereof. No interest shall be payable or otherwise owed with respect to such DERs for the period
of time beginning on the date a distribution is paid to the Partnership’s unitholders and ending on
the date the DERs are paid to you pursuant to this Agreement.
6.
Termination of Board Service. If your service as a member of the Board terminates
for any reason, then the portion of the Phantom Unit Award (and any associated DERs) for which
the Forfeiture Restrictions have not lapsed as of the date of termination shall become null and void
and such Phantom Units shall be forfeited.
7.
Leave of Absence. With respect to the Phantom Unit Award, the Partnership may,
in its sole discretion, determine that if you are on a leave of absence for any reason, you will be
considered to still be a Service Provider to the Partnership Group; provided, that rights to the
Phantom Unit Award during a leave of absence will be limited to the extent to which those rights
were earned or vested when the leave of absence began.
8.
Settlement Date; Manner of Settlement. Provided the Phantom Units have not been
forfeited pursuant to Section 6, promptly (but no later than 30 days) following the time of settlement
set forth in your Deferral Election Form, the Partnership shall deliver to you the number of Units
equal to the number of Phantom Units granted to you hereunder as to which the Deferral Period
has ended. In addition, the Partnership shall deliver to you an amount of cash equal to the DERs
that relate to the Phantom Units being settled. The amounts deliverable pursuant to this Section 8
shall not bear any interest owing to the passage of time.
2
9.
Right of the Partnership and its Affiliates to Terminate Services. Nothing in this
Agreement confers upon you the right to continue as a Service Provider for the Partnership or its
Affiliates, or interfere in any way with the rights of the Partnership or its Affiliates to terminate
your service relationship at any time.
10.
Furnish Information. You agree to furnish to the Partnership all information
requested by the Partnership to enable it to comply with any reporting or other requirements imposed
upon the Partnership by or under any applicable statute or regulation.
11.
No Liability for Good Faith Determinations. The Partnership and the members of
the Board shall not be liable for any act, omission or determination taken or made in good faith
with respect to this Agreement or the Phantom Unit Award.
12.
Executions of Receipts and Releases. Any payment of cash or other property to you,
or to your legal representative, heir, legatee or distributee in accordance with the provisions hereof,
shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The
Partnership may require you or your legal representative, heir, legatee or distributee, as a condition
precedent to such payment or issuance, to execute a release and receipt therefor in such form as it
shall determine.
13.
No Guarantee of Interests. The Board and the Partnership do not guarantee the
Phantom Units from loss or depreciation.
14.
Partnership Records. Records of the Partnership or its Affiliates regarding your
period of service, termination of service and the reason(s) therefor, leaves of absence, re-
employment, and other matters shall be conclusive for all purposes hereunder, unless determined
by the Partnership to be incorrect.
15.
Notice. All notices required or permitted under this Agreement must be in writing
and personally delivered or sent by mail and shall be deemed to be delivered on the date on which
it is actually received by the Person to whom it is properly addressed or if earlier, the date it is sent
via certified United States mail or reputable overnight delivery service (charges prepaid).
16. Waiver of Notice. Any Person entitled to notice hereunder may waive such notice
in writing.
17.
Successors. The Partnership may assign any of its rights under this Agreement
without your consent. This Agreement shall be binding upon and inure to the benefit of the successors
and assigns of GP LLC, the General Partner and the Partnership. Subject to the restrictions on
transfer set forth herein and in the Plan, this Agreement shall be binding upon and enforceable
against you and your beneficiaries, executors, administrators and the person(s) to whom the Phantom
Unit Award may be transferred by will or the laws of descent or distribution.
18.
Tax Consultation. Service Provider acknowledges and agrees that (a) Service
Provider is not relying upon any determination by GP LLC, the General Partner, the Partnership,
any of their respective Affiliates, or any of their respective employees, directors, officers, attorneys,
3
or agents (collectively, the “Partnership Parties”) of the Fair Market Value of the Units on the Date
of Grant, (b) Service Provider is not relying upon any written or oral statement or representation
of the Partnership Parties regarding the tax effects associated with your execution of the Agreement
and his or her receipt, holding and vesting of the Phantom Unit Award, and (c) in deciding to enter
into this Agreement, Service Provider is relying on his or her own judgment and the judgment of
the professionals of Service Provider’s choice with whom he or she has consulted. Service Provider
hereby releases, acquits and forever discharges the Partnership Parties from all actions, causes of
actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any
nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the
tax effects associated with Service Provider’s execution of the Agreement and his or her receipt,
holding and exercise of the Phantom Unit Award.
19.
Severability. If any provision of this Agreement is held to be illegal or invalid for
any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such
provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal
or invalid provision had never been included herein.
20.
Partnership or Committee Action. Any action required of GP LLC, the Partnership
or the General Partner shall be by resolution of the Board or Committee or by a Person or entity
authorized to act by resolution of the Board or Committee.
21.
Headings. The titles and headings of Sections are included for convenience of
reference only and are not to be considered in construction of the provisions hereof.
22.
Governing Law. All questions arising with respect to the provisions of this
Agreement shall be determined by application of the laws of the State of Delaware, without giving
any effect to any conflict of law provisions thereof, except to the extent Delaware state law is
preempted by federal law.
23.
Consent to Electronic Delivery; Electronic Signature. In lieu of receiving documents
in paper format, the Service Provider hereby consents to receive documents from the Partnership,
GP LLC, the General Partner, and any plan administrator by means of electronic delivery, provided
that such delivery complies with the rules, regulations and guidance issued by the Securities and
Exchange Commission and any other applicable government agency. This consent shall be effective
for the entire time that the Service Provider is a participant in the Plan.
24.
Consent to Jurisdiction and Venue. You hereby consent and agree that state courts
located in Harris County, Texas and the United States District Court for the Southern District of
Texas each shall have personal jurisdiction and proper venue with respect to any dispute between
you and the Partnership (or its Affiliate) arising in connection with the Phantom Unit Award or this
Agreement. In any dispute with the Partnership (or its Affiliate), you will not raise, and you hereby
expressly waive, any objection or defense to any such jurisdiction as an inconvenient forum.
25.
Amendment. This Agreement may be amended by the Board or by the Committee
at any time in a manner consistent with Section 7(a) of the Plan.
4
26.
Terms of Agreement. This Agreement is subject to all the terms, conditions,
limitations and restrictions contained in this Agreement, the Deferral Election Form and the Plan.
Together, this Agreement, the Deferral Election Form and the Plan constitute the entire agreement
of the parties with regard to the subject matter hereof, and contain all the covenants, promises,
representations, warranties and agreements between the parties with respect to the Phantom Units
granted hereby. Without limiting the scope of the preceding sentence, all prior understandings and
agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null
and void and of no further force and effect.
5
IN WITNESS HEREOF, GP LLC has caused this Agreement to be executed by its
officer thereto duly authorized, and Service Provider has set his or her hand as to the date
and year first written above.
GP Natural Resource Partners LLC,
a Delaware limited liability company
By:
Name:
Title:
[NON-EMPLOYEE DIRECTOR]
6
Exhibit 21.1
List of Subsidiaries of Natural Resource Partners L.P.
NRP (Operating) LLC
NRP Oil and Gas LLC
NRP Finance Corporation
WPP LLC
ACIN LLC
WBRD LLC
Hod LLC
Shepard Boone Coal Company LLC
Gatling Mineral, LLC
Independence Land Company, LLC
Williamson Transport, LLC
Little River Transport, LLC
Rivervista Mining, LLC
Deepwater Transportation, LLC
NRP Trona LLC
BRP LLC (51% interest)
CoVal Leasing Company, LLC (51% interest)
Consent of Independent Registered Public Accounting Firm
Exhibit 23.1
We consent to the incorporation by reference in the following Registration Statements:
1) Registration Statement (Form S-3 No. 333-217205) of Natural Resource Partners L.P.,
2) Registration Statement (Form S-3 No. 333-187883) of Natural Resource Partners L.P., and
3) Registration Statement (Form S-8 No. 333-222970) pertaining to the Natural Resource Partners L.P. 2017 Long-Term
Incentive Plan;
of our reports dated February 27, 2020, with respect to the consolidated financial statements of Natural Resource Partners L.P.,
and the effectiveness of internal control over financial reporting of Natural Resource Partners L.P., included in this Annual Report
(Form 10-K) of Natural Resource Partners L.P. for the year ended December 31, 2019.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2020
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement Nos. 333-217205 and 333-187883 on Form S-3 and
Registration Statement No. 333-222970 Form S-8 of Natural Resource Partners LP, of our report dated February 27, 2020, relating
to the financial statements of Ciner Wyoming LLC as of December 31, 2019 and 2018, and for the three years in the period ended
December 31, 2019, appearing in this Annual Report on Form 10-K of Natural Resource Partners LP for the year ended
December 31, 2019.
Exhibit 23.2
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2020
Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
I, Corbin J. Robertson, Jr., certify that:
1
2
3
4
I have reviewed this report on Form 10-K of Natural Resource Partners L.P.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
b.
c.
d.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions);
a.
b.
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
By:
/s/ Corbin J. Robertson, Jr.
Corbin J. Robertson, Jr.
Chief Executive Officer
Date: February 27, 2020
Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
I, Christopher J. Zolas, certify that:
1.
2.
3.
4.
I have reviewed this report on Form 10-K of Natural Resource Partners L.P.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
b.
c.
d.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions);
a.
b.
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
By:
/s/ Christopher J. Zolas
Christopher J. Zolas
Chief Financial Officer
Date: February 27, 2020
Exhibit 32.1
CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
In connection with the accompanying report on Form 10-K for the year ended December 31, 2019 filed with the Securities
and Exchange Commission on the date hereof (the “Report”), I, Corbin J. Robertson, Jr., Chief Executive Officer of GP Natural
Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the “Company”), hereby
certify, to my knowledge, that:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
By:
/s/ Corbin J. Robertson, Jr.
Corbin J. Robertson, Jr.
Chief Executive Officer
Date: February 27, 2020
Exhibit 32.2
CERTIFICATION OF
CHIEF FINANCIAL OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
In connection with the accompanying report on Form 10-K for the year ended December 31, 2019 filed with the Securities
and Exchange Commission on the date hereof (the “Report”), I, Christopher J. Zolas, Chief Financial Officer of GP Natural
Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the “Company”), hereby
certify, to my knowledge, that:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
By:
/s/ Christopher J. Zolas
Christopher J. Zolas
Chief Financial Officer
Date: February 27, 2020
Exhibit 99.1
Ciner Wyoming LLC
(A Majority-Owned Subsidiary of Ciner Resources LP)
Financial Statements as of December 31, 2019 and 2018 and for the Years Ended
December 31, 2019, 2018, and 2017, and Report of Independent Registered Public
Accounting Firm
1
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
TABLE OF CONTENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
BALANCE SHEETS AS OF DECEMBER 31, 2019 AND 2018
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED
DECEMBER 31, 2019, 2018 AND 2017
STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 2019, 2018 AND 2017
STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017
NOTES TO THE FINANCIAL STATEMENTS
Page
Number
3
4
5
6
7
8
2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ciner Wyoming LLC (“the Company”) as of December 31, 2019 and 2018,
and the related statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years
in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion,
the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and
2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in
conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not
required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits,
we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an
opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due
to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2020
We have served as the Company’s auditor since 2008.
3
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
BALANCE SHEETS
AS OF DECEMBER 31, 2019 AND 2018
(In thousands of dollars)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable - affiliates
Accounts receivable, net
Inventory
Other current assets
Total current assets
PROPERTY, PLANT, AND EQUIPMENT, NET
OTHER NON-CURRENT ASSETS
TOTAL ASSETS
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable
Due to affiliates
Accrued expenses
Total current liabilities
LONG-TERM DEBT
OTHER NON-CURRENT LIABILITIES
Total liabilities
COMMITMENTS AND CONTINGENCIES (See Note 12)
MEMBERS' EQUITY:
Members’ equity — Ciner Resources LP
Members’ equity — Natural Resource Partners LP
Accumulated other comprehensive loss
Total members' equity
2019
2018
$
$
13,684
95,115
35,963
24,193
1,741
7,124
70,359
36,870
22,275
1,452
170,696
138,080
258,121
226,411
24,266
26,332
$
453,083
$
390,823
$
$
14,163
3,215
37,961
55,339
129,500
8,587
17,478
2,843
43,691
64,012
99,000
10,921
193,426
173,933
135,423
130,113
(5,879)
114,434
109,947
(7,491)
259,657
216,890
TOTAL LIABILITIES AND MEMBERS' EQUITY
$
453,083
$
390,823
See notes to financial statements.
4
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017
(In thousands of dollars)
SALES - AFFILIATES
SALES - OTHERS
Total net sales
COST OF PRODUCTS SOLD
FREIGHT COSTS
Total cost of products sold
GROSS PROFIT
2019
2018
2017
$
315,847
206,996
522,843
247,790
143,341
391,131
131,712
$
$
253,345
233,414
486,759
243,562
139,144
304,497
192,843
497,340
237,445
145,693
382,706
383,138
104,053
114,202
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES
18,404
17,698
16,520
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS
LOSS ON DISPOSAL OF ASSETS, NET
LITIGATION SETTLEMENT GAIN
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest income
Interest expense
Other expense, net
Total other expense
NET INCOME
OTHER COMPREHENSIVE INCOME (LOSS)
1,553
—
—
2,106
—
(27,500)
1,543
1,569
—
111,755
111,749
94,570
350
(5,893)
(57)
1,871
(5,058)
(205)
1,663
(4,531)
(179)
(5,600)
(3,392)
(3,047)
106,155
108,357
91,523
Income (loss) on derivative financial instruments
1,612
(282)
(3,930)
COMPREHENSIVE INCOME
$
107,767
$
108,075
$
87,593
See notes to financial statements.
5
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF MEMBERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017
(In thousands of dollars)
Balance at December 31, 2016
Allocation of net income
Capital distribution to members
Other comprehensive loss
Balance at December 31, 2017
Allocation of net income
Capital distribution to members
Other comprehensive loss
Balance at December 31, 2018
Allocation of net income
Capital distribution to members
Other comprehensive income
Balance at December 31, 2019
Ciner
Resources LP
Natural
Resource
Partners LP
Accumulated
Other
Comprehensive
(Loss) Income
Total
Members'
Equity
$
$
$
$
111,945
$
107,556
$
(3,279) $
216,222
46,677
(51,000)
—
44,846
(49,000)
—
—
—
(3,930)
91,523
(100,000)
(3,930)
107,622
$
103,402
$
(7,209) $
203,815
55,262
(48,450)
—
53,095
(46,550)
—
—
—
(282)
108,357
(95,000)
(282)
114,434
$
109,947
$
(7,491) $
216,890
54,139
(33,150)
—
52,016
(31,850)
—
—
—
1,612
106,155
(65,000)
1,612
135,423
$
130,113
$
(5,879) $
259,657
See notes to financial statements.
6
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
106,155
$
108,357
$
91,523
2019
2018
2017
Depreciation, depletion and amortization
Loss on disposal of assets, net
Other non-cash items
(Increase) decrease in:
Accounts receivable - affiliates
Accounts receivable, net
Inventory
Other current and non-current assets
Increase (decrease) in:
Accounts payable
Accrued expenses and other liabilities
Due to affiliates
26,440
642
304
(24,756)
907
(385)
(123)
(3,073)
(73)
372
27,996
—
448
28,152
(2,683)
(3,025)
(228)
2,350
4,067
(240)
Net cash provided by operating activities
106,410
165,194
26,827
1,569
299
(36,691)
(792)
498
(189)
1,679
(1,124)
(1,124)
82,475
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on revolving credit facility
Repayments on revolving credit facility
Repayments on other long-term debt
Debt issuance costs
Cash distribution to members
Net cash used in financing activities
(65,350)
(39,419)
(24,757)
(65,350)
(39,419)
(24,757)
102,000
(71,500)
—
—
(65,000)
104,000
(143,000)
(11,400)
—
(95,000)
88,500
(28,500)
(8,600)
(1,097)
(100,000)
(34,500)
(145,400)
(49,697)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
6,560
(19,625)
8,021
CASH AND CASH EQUIVALENTS:
Beginning of year
End of year
SUPPLEMENTAL DISLCOSURES OF CASH FLOW INFORMATION:
Interest paid during the year
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES :
Capital expenditures on account
7,124
26,749
18,728
13,684
$
7,124
$
26,749
5,476
$
5,141
$
4,097
6,786
$
14,002
$
1,034
$
$
$
See notes to financial statements.
7
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
NOTES TO FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2019 AND 2018 AND FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017
(Dollars in thousands)
1. Corporate Structure
A 51% membership interest in Ciner Wyoming LLC (the "Company," "Ciner Wyoming," "we," "us," or "our") is owned
by Ciner Resources LP ("Ciner Resources" or the "Partnership"). NRP Trona LLC, a wholly owned subsidiary of Natural
Resource Partners LP ("NRP") owns a 49% membership interest in the Company. Ciner Resources is a master limited
partnership traded on the New York Stock Exchange and is currently owned approximately 72% by Ciner Wyoming
Holding Co. ("Ciner Holdings"), approximately 2% by Ciner Resource Partners LLC (our “general partner” or “Ciner
GP”) and approximately 26% by the general public. Ciner Holdings is 100% owned by Ciner Resources Corporation
("Ciner Corp") which is 100% owned by Ciner Enterprises, Inc. ("Ciner Enterprises"). As of December 31, 2019, Ciner
Enterprises was 100% owned by WE Soda Ltd., a U.K. corporation (“WE Soda”). WE Soda is a direct wholly-owned
subsidiary of KEW Soda Ltd., a U.K. corporation (“KEW Soda”), which is a direct wholly-owned subsidiary of Akkan
Enerji ve Madencilik Anonim
irketi ("Akkan"), which is 100% owned by Turgay Ciner, the Chairman of the Ciner
Group, a Turkish conglomerate of companies engaged in energy and mining (including soda ash mining), media and
shipping markets.
On February 22, 2018, Akkan transferred its direct 100% ownership in Ciner Enterprises to KEW Soda, a U.K. company,
which transferred such ownership to WE Soda, a U.K. company. WE Soda is 100% owned by KEW Soda, and KEW
Soda is wholly owned by Akkan. This reorganization is a part of Ciner Group’s strategy to combine the global soda ash
business under a common structure in the U.K.
2. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations
The Company's operations consist of the mining of trona ore, which, when processed, becomes soda ash. All our soda
ash processed is sold to various domestic customers, and to American Natural Soda Ash Corporation ("ANSAC"), which
is an affiliate for export sales. All mining and processing activities take place in one facility located in Green River,
Wyoming. The Company began selling soda ash in late 2016 to Ciner Ic ve Dis Ticaret Anonim Sirketi ("CIDT"), an
affiliate for export sales, and continued into 2017. However, there were no sales to CIDT during the years ended
December 31, 2019 and December 31, 2018, as the contract with CIDT terminated in 2017.
ANSAC Exit - On November 9, 2018, Ciner Resources Corporation delivered a notice to terminate its membership in
ANSAC, a cooperative that serves as the primary international distribution channel for the Company as well as two other
U.S. manufacturers of trona-based soda ash. The effective termination date of Ciner Corp’s membership in ANSAC is
December 31, 2021 (the “ANSAC termination date”). In the event an ANSAC member exits or the ANSAC cooperative
is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the
cooperative. Potential liabilities associated with exiting ANSAC are not currently probable or estimable.
ANSAC was the Company's largest customer for the years ended December 31, 2019, 2018 and 2017, accounting for
60.4%, 52.0% and 44.7%, respectively, of the Company's net sales. Although ANSAC has been the Company's largest
customer for the years ended December 31, 2019, 2018, and 2017, the Company anticipates that the impact of such
termination on its net sales, net income and liquidity will be limited. The Company made this determination primarily
8
based upon the belief that it will continue to be one of the lowest cost producers of soda ash in the global market that has
historically seen demand for soda ash exceed supply of soda ash. After the ANSAC termination date, the Company
expects Ciner Corp will begin marketing soda ash directly on the Company's behalf into international markets which are
currently being served by ANSAC and intends to utilize the distribution network that has already been established by the
global Ciner Group. The Company believes that by combining its volumes with Ciner Group’s soda ash exports from
Turkey, Ciner Corp's withdrawal from ANSAC will allow the Company to leverage the larger, global Ciner Group’s soda
ash operations which the Company expects will eventually lower its cost position and improve its ability to optimize our
market share both domestically and internationally. Further, being able to work with the global Ciner Group will provide
the Company the opportunity to attract and efficiently serve larger global customers. In addition, the Company will need
access to an international logistics infrastructure that includes, among other things, a domestic port for export capabilities.
These export capabilities are currently being developed by Ciner Enterprises and options being evaluated range from
continued outsourcing in the near term to developing its own port capabilities in the longer term. The development costs
of export capabilities are currently being paid by Ciner Enterprises, who are evaluating how these costs might be
allocated to the Company, which could include ownership by the Company and repayment for the development costs and
related assets or a service agreement model for logistics services which includes reimbursements for development costs.
Since a decision to allocate costs to the Company has not been made yet and the Company is not currently using any
Ciner Enterprises export services, none of these development costs have been recorded by the Company through
December 31, 2019.
A summary of the significant accounting policies is as follows:
Basis of Presentation - The accompanying financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America.
Use of Estimates - The preparation of financial statements, in accordance with accounting principles generally accepted in
the United States of America, requires management to make estimates and assumptions that affect the reported amounts
of assets and liabilities, and disclosure of contingent assets and liabilities at the dates of the financial statements, and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition - On May 28, 2014 the Financial Accounting Standards Board (the “FASB”) issued Accounting
Standards Codification (“ASC”) 606, Revenue from Contracts with Customer, that requires companies to recognize
revenue when a customer obtains control rather than when companies have transferred substantially all risks and rewards
of a good or service. The Company adopted this ASC effective January 1, 2018, as permitted by the ASC, using the
modified retrospective method and we have not made any adjustment to opening retained earnings. The Company has
applied the provisions of this ASC and notes that our adoption of ASC 606 does not materially change the amount or
timing of revenues recognized by us, nor does it materially affect our financial position. The majority of our revenues
generated are recognized upon delivery and transfer of title to the product to our customers. The time at which delivery
and transfer of title occurs, for the majority of our contracts with customers, is the point when the product leaves our
facility, thereby rendering our performance obligation fulfilled. Additionally, the Company has made an accounting
policy election to account for shipping and handling activities as fulfillment costs.
Freight Costs - The Company includes freight costs billed to customers for shipments administered by the Company in
gross sales. The related freight costs along with cost of products sold are deducted from gross sales to determine gross
profit.
Cash and Cash Equivalents - The Company considers all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents. Cash equivalents consist primarily of money market deposit accounts.
Accounts Receivable - Accounts receivable are carried at the original invoice amount less an estimate for doubtful
receivables. We generally do not require collateral against outstanding accounts receivable. The allowance for doubtful
9
accounts is based on specifically identified amounts that the Company believes to be uncollectible. An additional
allowance is recorded based on certain percentages of aged receivables, which are determined based on management’s
assessment of the general financial conditions affecting the Company’s customer base. We determined that no allowance
for doubtful accounts was required against receivables from affiliates as of December 31, 2019 and 2018. If actual
collection experience changes, revisions to the allowance may be required. Accounts receivable are written off when
deemed uncollectible. Recoveries of accounts receivable previously written off are recorded when received. During the
years ended December 31, 2019, 2018 and 2017, there were no significant accounts receivable bad debt expenses, write-
offs or recoveries.
Inventory - Inventory is carried at the lower of cost or market. Cost is determined using the first-in, first-out method for
raw material and finished goods inventory and the weighted average cost method for stores inventory. Costs include raw
materials, direct labor and manufacturing overhead. Market is based on current replacement cost for raw materials and net
realizable value for stores inventory and finished goods.
• Raw material inventory includes material, chemicals and natural resources being used in the mining and refining
process.
• Finished goods inventory is the finished product soda ash.
• Stores inventory includes parts, materials and operating supplies which are typically consumed in the production of
soda ash and currently available for future use. Inventory expected to be consumed within the year is classified as current
assets and remainder is classified as non-current assets.
Property, Plant, and Equipment - Property, plant, and equipment are stated at cost less accumulated depreciation.
Depreciation is computed over the estimated useful lives of depreciable assets, using the straight-line method. The
estimated useful lives applied to depreciable assets are as follows:
Land improvements
Depletable land
Buildings and building improvements
Computer hardware
Machinery and equipment
Furniture and fixtures
Useful Lives
10 years
15-60 years
10-30 years
3-5 years
5-20 years
10 years
The Company's policy is to evaluate property, plant, and equipment for impairment whenever events or changes in
circumstances indicate that its carrying amount may not be recoverable. An indicator of potential impairment would
include situations when the estimated future undiscounted cash flows are less than the carrying value. The amount of any
impairment then recognized would be calculated as the difference between estimated fair value and the carrying value of
the asset.
Derivative Instruments and Hedging Activities - The Company may enter into derivative contracts from time to time to
manage exposure to the risk of exchange rate changes on its foreign currency transactions, the risk of changes in natural
gas prices, and the risk of the variability in interest rates on borrowings. Gains and losses on derivative contracts
qualifying for hedge accounting are reported as a component of the underlying transactions. The Company follows hedge
accounting for its hedging activities. All derivative instruments are recorded on the balance sheet at their fair values. The
accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting
designation. The Company designates its derivatives based upon criteria established for hedge accounting under generally
accepted accounting principles. For a derivative designated as a fair value hedge, the gain or loss is recognized in
earnings in the period of change together with the offsetting gain or loss on the hedged item attributed to the risk being
10
hedged. For a derivative designated as a cash flow hedge, the effective portion of the derivative’s gain or loss is initially
reported as a component of accumulated other comprehensive income (loss) and subsequently reclassified into earnings
when the hedged exposure affects earnings. Any significant ineffective portion of the gain or loss is reported in earnings
immediately. For derivatives not designated as hedges, the gain or loss is reported in earnings in the period of change. The
natural gas physical forward contracts are accounted for under the normal purchases and normal sales scope exception.
The Company has interest rate swap contracts, designated as cash flow hedges, to mitigate our exposure to possible
increases in interest rates. The swap contracts consist of four individual $12,500 swaps with an aggregate notional value
of $50,000 at both December 31, 2019 and December 31, 2018, and have various maturities through 2023. At
December 31, 2019, it is anticipated that approximately $855 of losses currently recorded in accumulated other
comprehensive income (loss) will be reclassified into earnings within the next twelve months.
The Company has entered into financial natural gas forward contracts, designed as cash flow hedges, to mitigate volatility
in the price of the natural gas the Company consumes. These contracts generally have various maturities through 2024.
These contracts had an aggregate notional value of $31,196 and $41,206 at December 31, 2019 and December 31, 2018
respectively. Refer to footnote 12 for details surrounding both the physical and financial portions of our natural gas
forward contracts. At December 31, 2019, it was anticipated that $2,264 of losses currently recorded in accumulated other
comprehensive income (loss) will be reclassified into earnings within the next twelve months.
The following table presents the fair value of derivative assets and liabilities and the respective balance sheet locations as
of:
Assets
Liabilities
December 31,
2019
December 31,
2018
December 31,
2019
December 31,
2018
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Derivatives designated as
hedges:
Interest rate swap contracts -
current
Natural gas forward contracts -
current
Natural gas forward contracts -
non-current
Total derivatives designated
as hedging instruments
Other
current
assets
Other
Non-
current
assets
$
—
136
155
291
$
$
$
Accrued
Expenses
Accrued
Expenses
Other
non-
current
liabilities
$
855
2,400
2,915
Accrued
Expenses
Accrued
Expenses
Other
non-
current
liabilities
$
319
1,617
5,555
$
6,170
$
7,491
—
—
—
—
Income Tax - The Company is organized as a pass-through entity for federal and most state income tax purposes. Taxes
assessed by states on the Company are de minimis. As a result, the members are responsible for federal income taxes
based on their respective share of taxable income. Net income for financial statement purposes may differ significantly
from taxable income reportable to members as a result of differences between the tax bases and financial reporting bases
of assets and liabilities and the taxable income allocation requirements under the membership agreement.
Reclamation Costs - The Company is obligated to return the land beneath its refinery and tailings ponds to its natural
condition upon completion of operations and is required to return the land beneath its rail yard to its natural condition
upon termination of the various lease agreements.
The Company accounts for its land reclamation liability as an asset retirement obligation, which requires that obligations
associated with the retirement of a tangible long-lived asset be recorded as a liability when those obligations are incurred,
11
with the amount of the liability initially measured at fair value. Upon initially recognizing a liability for an asset
retirement obligation, an entity must capitalize the cost by recognizing an increase in the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated
over the estimated useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for
its recorded amount or incurs a gain or loss upon settlement.
The estimated original liability calculated in 1996 for the refinery and tailing ponds was calculated based on the estimated
useful life of the mine, which was 80 years, and on external and internal estimates as to the cost to restore the land in the
future and state regulatory requirements. During 2019, 2018 and 2017 the estimated remaining estimated useful life of the
mine was 59 years, 60 years and 66 years, respectively. In 2020, the mining reserve will be amortized over a remaining
life of 58 years. The decline in estimated mining reserves estimated remaining life is based on the results of an
independent mine reserve analysis conducted as of December 31, 2017. The independent mine reserve analysis is routine
and performed approximately every three years. The liability was discounted using a weighted average credit-adjusted
risk-free rates of approximately 6% and is being accreted throughout the estimated life of the related assets to equal the
total estimated costs with a corresponding charge being recorded to cost of products sold.
During 2011, the Company constructed a rail yard to facilitate loading and switching of rail cars. The Company is
required to restore the land on which the rail yard is constructed to its natural conditions. The original estimated liability
for restoring the rail yard to its natural condition was calculated based on the land lease life of 30 years and on external
and internal estimates as to the cost to restore the land in the future. The liability is discounted using a credit-adjusted
risk-free rate of 4.25% and is being accreted throughout the estimated life of the related assets to equal the total estimated
costs with a corresponding charge being recorded to cost of products sold.
Fair Value of Financial Instruments - The following methods and assumptions were used to estimate the fair values of
each class of financial instruments:
Financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, accrued
expenses, derivative financial instruments and long-term debt. The carrying amounts of cash and cash equivalents,
accounts receivable, accounts payable and accrued expenses approximate their fair value because of the nature of such
instruments. Our long-term debt and derivative financial instruments are measured at their fair values with Level 2 inputs
based on quoted market values for similar but not identical financial instruments.
Long-Term Debt - The carrying value of our long-term debt materially reflects the fair value of our long-term debt as
rates are variable and its key terms are similar to indebtedness with similar amounts, durations and credit risks.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair
value measurement. Fair value accounting requires that these financial assets and liabilities be classified into one of the
following three categories:
• Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for an identical asset or liability in an active
market.
• Level 2-inputs to the valuation methodology include quoted prices for a similar asset or liability in an active market or
model-derived valuations in which all significant inputs are observable for substantially the full term of the asset or
liability.
• Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement of the asset
or liability.
Subsequent Events - The Company has evaluated all subsequent events through February 27, 2020, the date the financial
statements were available to be issued. See Note 16 - Subsequent Event for additional information.
12
Recently Issued Accounting Standards - In February 2016, the FASB issued Accounting Standards Update (“ASU”)
2016-02, Leases (Topic 842) to increase the transparency and comparability of leases among entities. Additional ASUs
have been issued subsequent to ASU 2016-02 to provide supplementary clarification and implementation guidance for
leases related to, among other things, the application of certain practical expedients, the rate implicit in the lease, lessee
reassessment of lease classification, lessor reassessment of lease term and purchase options, variable payments that
depend on an index or rate and certain transition adjustments. ASU 2016-02 and these additional ASUs are now codified
as ASC 842. Pursuant to these updates, accounting for leases by lessors remains largely unchanged from current
guidance. The update requires that lessees recognize a lease liability and a right of use asset for all leases (with the
exception of short-term leases) at the commencement date of the lease and disclose key information about leasing
arrangements. For leases less than 12 months, an entity is permitted to make an accounting policy election by class of
underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease
expense for such leases generally on a straight-line basis over the lease term. The Company made this election upon
adoption. The Company adopted ASC 842 effective January 1, 2019 using a modified retrospective approach under which
prior comparative periods were not adjusted, as permitted by the guidance. The Company has determined that the
adoption of the new standard did not have a material impact on the balance sheet or statement of operations because the
Company has no material long term leases that are subject to ASC 842. Ciner Corp was determined to be the ultimate
lessee for rail car lease agreements under ASC 842, and the Company will continue to incur an allocation of rent expense
in relation to the use of rail cars leased by Ciner Corp.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (“ASU Topic 815”) - Targeted Improvements
to Accounting for Hedging Activities. ASU Topic 815 aims to improve the financial reporting of hedging relationships to
better portray the economic results of an entity’s risk management activities in its financial statements. In addition, ASU
Topic 815 makes certain targeted improvements to simplify the application of the existing hedge accounting guidance.
The Company adopted ASU Topic 815 effective January 1, 2019 and concluded there was no material impact to the
Company’s financial statements.
Recent Guidance Not Adopted Yet - In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit
Losses (Topic 326)” ("ASU 2016-13"). This ASU introduces the current expected credit loss (CECL) model, which will
require an entity to measure credit losses for certain financial instruments and financial assets, including trade
receivables. Under this update, on initial recognition and at each reporting period, an entity will be required to recognize
an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial
instrument. ASU 2016-13 is effective for periods beginning after December 15, 2019. The Company continues to evaluate
ASU 2016-13 but does not expect a material impact to the Company’s financial statements.
In August 2018, the FASB issued ASU 2018-15, “Intangibles-Goodwill and Other-Internal-Use Software (Subtopic
350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service
Contract (a consensus of the FASB Emerging Issues Task Force)” (“ASU 2018-15”), which amends ASC 350-40 to
address a customer’s accounting for implementation costs incurred in a cloud computing arrangement (“CCA”) that is a
service contract. ASU 2018-15 amends ASC 350 and clarifies that a customer should apply ASC 350-40 to determine
which implementation costs should be capitalized in a CCA. ASU 2018-15 does not expand on existing disclosure
requirements except to require a description of the nature of hosting arrangements that are service contracts. Entities are
permitted to apply either a retrospective or prospective transition approach to adopt the guidance. ASU 2018-15 is
effective for periods beginning after December 15, 2019. The Company continues to evaluate ASU 2018-15 but does not
expect a material impact to the Company’s financial statements.
13
3. ACCOUNTS RECEIVABLE, NET
Accounts receivable, net as of December 31, 2019 and 2018 consisted of the following:
2019
2018
Trade receivables
Other receivables
Allowance for doubtful accounts
Total
4. INVENTORY
Inventory as of December 31, 2019 and 2018 consisted of the following:
Raw materials
Finished goods
Stores inventory, current
Total
$
$
$
$
30,281
5,742
36,023
(60)
35,963
2019
8,672
6,894
8,627
24,193
5. PROPERTY, PLANT, AND EQUIPMENT, NET
Property, plant, and equipment as of December 31, 2019 and 2018 consisted of the following:
Land and land improvements
Depletable land
Buildings and building improvements
Computer hardware
Machinery and equipment
Total
Less accumulated depreciation, depletion and amortization
Total net book value
Construction in progress
Property, plant, and equipment, net
2019
192
2,957
137,937
4,734
644,132
789,952
(622,545)
167,407
90,714
258,121
$
$
$
$
$
$
$
$
30,993
5,897
36,890
(20)
36,870
2018
10,867
5,112
6,296
22,275
2018
192
2,957
137,176
4,680
649,488
794,493
(614,415)
180,078
46,333
226,411
Depreciation, depletion and amortization expense on property, plant and equipment was $26,175, $27,731 and $26,418
for the years ended December 31, 2019, 2018 and 2017, respectively.
The increase in construction in progress from December 31, 2018 to December 31, 2019 is due to construction on a co-
generation facility which we are planning to be operational by the end of the first quarter of 2020 and the execution of the
early phases for a Green River Expansion Project that we believe will significantly increase production levels of soda ash.
6. OTHER NON-CURRENT ASSETS
Other non-current assets as of December 31, 2019 and 2018 consisted of the following:
Stores inventory, non-current
Internal-use software, net of accumulated amortization
Deferred financing costs and other
Total
2019
2018
17,571
6,088
607
24,266
$
$
19,394
6,191
747
26,332
$
$
During the years ended December 31, 2019, 2018 and 2017, in accordance with ASC 350-40, Internal Use Software, we
capitalized $596, $6,191 and $0, respectively, of certain internal use software development costs. Software development
14
activities generally consist of three stages (i) the research and planning stage, (ii) the application and infrastructure
development stage, and (iii) the post-implementation stage. Costs incurred in the planning and post-implementation
stages of software development, or other maintenance and development expenses that do not meet the qualification for
capitalization are expensed as incurred. Costs incurred in the application and infrastructure development stage, including
significant enhancements and upgrades, are capitalized. These software development costs are amortized on a straight-
line basis over the estimated useful life of five to ten years under depreciation and amortization expense which is included
in the cost of products sold financial statement line item of the statements of operations. During the years ended
December 31, 2019, 2018 and 2017, we amortized internal use software development costs of $699, $0 and $0,
respectively. Amortization for these internal use software development costs are expected to be approximately $699 per
year during the amortization period.
7. ACCRUED EXPENSES
Accrued expenses as of December 31, 2019 and 2018 consisted of the following:
Accrued capital expenditures
Accrued employee compensation & benefits
Accrued energy costs
Accrued royalty costs
Accrued other taxes
Accrued derivatives
Other accruals
Total
8. DEBT
2019
2018
$
$
6,156
6,898
5,654
7,143
4,801
3,255
4,054
37,961
$
$
13,131
7,083
6,592
6,529
4,747
1,936
3,673
43,691
Long-term debt as of December 31, 2019 and 2018 consisted of the following:
Ciner Wyoming Credit Facility, unsecured principal expiring on August 1, 2022, variable
interest rate as a weighted average rate of 3.27% and 3.99% at December 31, 2019 and 2018,
respectively
Total long-term debt
$
$
129,500
129,500
$
$
99,000
99,000
2019
2018
Aggregate maturities required on long-term debt at December 31, 2019 are due in future years as follows:
2020 - 2021
2022
2023 and thereafter
Total
Ciner Wyoming Credit Facility
$
$
—
129,500
—
129,500
On August 1, 2017, Ciner Wyoming entered into a Credit Agreement (“Ciner Wyoming Credit Facility”) with each of the
lenders listed on the respective signature pages thereof and PNC Bank, National Association, as administrative agent,
swing line lender and a Letter of Credit (“L/C”) issuer. The Ciner Wyoming Credit Facility replaces the former Credit
Facility (“Former Ciner Wyoming Credit Facility”), dated as of July 18, 2013, by and among Ciner Wyoming, the lenders
party thereto and Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, as amended, which
was terminated on August 1, 2017 upon entry into the Ciner Wyoming Credit Facility. This arrangement was accounted
for as a modification of debt in accordance with ASC 470-50.
The Ciner Wyoming Credit Facility is a $225,000 senior unsecured revolving credit facility with a syndicate of lenders,
which will mature on the fifth anniversary of the closing date of such credit facility. The Ciner Wyoming Credit Facility
15
provides for revolving loans to fund working capital requirements, capital expenditures, to consummate permitted
acquisitions and for all other lawful purposes. The Ciner Wyoming Credit Facility has an accordion feature that allows
Ciner Wyoming to increase the available revolving borrowings under the facility by up to an additional $75,000, subject
to Ciner Wyoming receiving increased commitments from existing lenders or new commitments from new lenders and
the satisfaction of certain other conditions. In addition, the Ciner Wyoming Credit Facility includes a sublimit up to
$20,000 for same-day swing line advances and a sublimit up to $40,000 for letters of credit. Ciner Wyoming’s obligations
under the Ciner Wyoming Credit Facility are unsecured.
The Ciner Wyoming Credit Facility contains various covenants and restrictive provisions that limit (subject to certain
exceptions) Ciner Wyoming’s ability to:
• make distributions on or redeem or repurchase units;
•
incur or guarantee additional debt;
• make certain investments and acquisitions;
•
incur certain liens or permit them to exist;
• enter into certain types of transactions with affiliates of Ciner Wyoming;
• merge or consolidate with another company; and
•
transfer, sell or otherwise dispose of assets.
The Ciner Wyoming Credit Facility also requires quarterly maintenance of a leverage ratio (as defined in the Ciner
Wyoming Credit Facility) of not more than 3.00 to 1.00 and an interest coverage ratio (as defined in the Ciner Wyoming
Credit Facility) of not less than 3.00 to 1.00.
The Ciner Wyoming Credit Facility contains events of default customary for transactions of this nature, including
(i) failure to make payments required under the Ciner Wyoming Credit Facility, (ii) events of default resulting from
failure to comply with covenants and financial ratios in the Ciner Wyoming Credit Facility, (iii) the occurrence of a
change of control, (iv) the institution of insolvency or similar proceedings against Ciner Wyoming and (v) the occurrence
of a default under any other material indebtedness Ciner Wyoming may have. Upon the occurrence and during the
continuation of an event of default, subject to the terms and conditions of the Ciner Wyoming Credit Facility, the
administrative agent shall, at the request of the Required Lenders (as defined in the Ciner Wyoming Credit Facility), or
may, with the consent of the Required Lenders, terminate all outstanding commitments under the Ciner Wyoming Credit
Facility and may declare any outstanding principal of the Ciner Wyoming Credit Facility debt, together with accrued and
unpaid interest, to be immediately due and payable.
Under the Ciner Wyoming Credit Facility, a change of control is triggered if Ciner Corp and its wholly-owned
subsidiaries, directly or indirectly, cease to own all of the equity interests, or cease to have the ability to elect a majority
of the board of directors (or similar governing body) of our general partner (or any entity that performs the functions of
the Partnership’s general partner). In addition, a change of control would be triggered if the Partnership ceases to own at
least 50.1% of the economic interests in Ciner Wyoming or ceases to have the ability to elect a majority of the members
of Ciner Wyoming’s board of managers.
Loans under the Ciner Wyoming Credit Facility bear interest at Ciner Wyoming’s option at either:
• a Base Rate, which equals the highest of (i) the federal funds rate in effect on such day plus 0.50%, (ii) the
administrative agent’s prime rate in effect on such day or (iii) one-month LIBOR plus 1.0%, in each case, plus
an applicable margin; or
16
• Eurodollar Rate plus an applicable margin.
The unused portion of the Ciner Wyoming Credit Facility is subject to an unused line fee ranging from 0.225% to 0.300%
per annum based on Ciner Wyoming’s then current leverage ratio.
At December 31, 2019, Ciner Wyoming was in compliance with all financial covenants of the Ciner Wyoming Credit
Facility.
WE Soda and Ciner Enterprises Facilities Agreement
On August 1, 2018, Ciner Enterprises, the entity that indirectly owns and controls Ciner Wyoming, refinanced its existing
credit agreement and entered into a new facilities agreement, to which WE Soda and Ciner Enterprises (as borrowers),
and KEW Soda, WE Soda, certain related parties and Ciner Enterprises, Ciner Holdings and Ciner Corp (as original
guarantors and together with the borrowers, the “Ciner obligors”), are parties (as amended and restated or otherwise
modified, the “Facilities Agreement”), and certain related finance documents. The Facilities Agreement expires on August
1, 2025.
Even though Ciner Wyoming is not a party or a guarantor under the Facilities Agreement, while any amounts are
outstanding under the Facilities Agreement we will be indirectly affected by certain affirmative and restrictive covenants
that apply to WE Soda and its subsidiaries (which includes us). Besides the customary covenants and restrictions, the
Facilities Agreement includes provisions that, without a waiver or amendment approved by lenders whose commitments
are more than 66-2/3% of the total commitments under the Facilities Agreement to undertake such action, would (i)
prevent transactions with our affiliates that could reasonably be expected to materially and adversely affect the interests
of certain finance parties, (ii) restrict the ability to amend the Company's agreement or Ciner Holdings' company
agreement or Company's other constituency documents if such amendment could reasonably be expected to materially
and adversely affect the interests of the lenders to the Facilities Agreement; and (iii) prevent actions that enable certain
restrictions or prohibitions on our ability to upstream cash (including via distributions) to the borrowers under the
Facilities Agreement. In addition, Ciner Enterprises’ ownership in Ciner Holdings, is subject to a lien under the Facilities
Agreement, which enables the lenders under the Facilities Agreement to foreclose on such collateral and take control of
Ciner Holdings if any of WE Soda or KEW Soda or certain of their related parties, or Ciner Enterprises, Ciner Corp or
Ciner Holdings is unable to satisfy its respective obligations under the Facilities Agreement.
17
9. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities as of December 31, 2019 and 2018 consisted of the following:
Reclamation reserve
Derivative instruments and hedges, fair value liabilities
Total
Details of the reclamation reserve shown above are as follows:
Reclamation reserve at beginning of year
Accretion expense
Reclamation reserve at end of year
10. EMPLOYEE BENEFIT PLANS
2019
2018
5,672
2,915
8,587
2019
5,366
306
5,672
$
$
$
$
5,366
5,555
10,921
2018
5,080
286
5,366
$
$
$
$
The Company participates in various benefit plans offered and administered by Ciner Corp and is allocated its portions of
the annual costs related thereto. The specific plans are as follows:
Retirement Plans - Benefits provided under the pension plan for salaried employees and pension plan for hourly
employees (collectively, the “Retirement Plans”) are based upon years of service and average compensation for the
highest 60 consecutive months of the employee’s last 120 months of service, as defined. Each Retirement Plan covers
substantially all full-time employees hired before May 1, 2001. Ciner Corp’s Retirement Plans had a net unfunded
liability balance of $54,800 and $56,883 at December 31, 2019 and December 31, 2018, respectively. Ciner Corp’s
current funding policy is to contribute an amount within the range of the minimum required and the maximum tax-
deductible contribution. The Company's allocated portion of the pension plans' net periodic pension costs was $994, $412
and $1,358 for the years ended December 31, 2019, 2018 and 2017, respectively. The increase in pension costs in 2019
was driven by asset changes from the prior year.
Savings Plan - The 401(k) retirement plan (the “401(k) Plan”) covers all eligible hourly and salaried employees.
Eligibility is limited to all domestic residents and any foreign expatriates who are in the United States indefinitely. The
401(k) Plan permits employees to contribute specified percentages of their compensation, while the Company makes
contributions based upon specified percentages of employee contributions. Participants hired on or subsequent to May 1,
2001, will receive an additional contribution from the Company based on a percentage of the participant’s base pay.
Contributions made to the 401(k) Plan for the years ended December 31, 2019, 2018 and 2017 were $3,032, $2,833 and
$3,735, respectively.
Postretirement Benefits - Most of the Company's employees are eligible for postretirement benefits other than pensions if
they reach retirement age while still employed.
The postretirement benefits are accounted for by Ciner Corp on an accrual basis over an employee’s period of service.
The postretirement plan, excluding pensions, is not funded, and Ciner Corp has the right to modify or terminate the plan.
The post-retirement plan had a net unfunded liability of $13,757 and $9,851 at December 31, 2019 and 2018, respectively.
The increase in the obligation as of December 31, 2019 as compared to December 31, 2018 is due to Ciner Corp
amending its postretirement benefit plan, updating it’s per capita claims costs to reflect increased benefit payments and a
decrease in the discount rate used to determine benefit obligations at December 31, 2019.
The Company's allocated portion of postretirement (benefit) costs was $(2,152), $(2,940) and $(2,823) for the years ended
December 31, 2019, 2018 and 2017, respectively. The postretirement benefit for the Company in 2019, 2018 and 2017 is
due to the aforementioned changes made to the postretirement benefit plan.
18
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss as of December 31, 2019, 2018 and 2017 consisted of the following:
BALANCE at December 31, 2016
Other comprehensive income (loss) before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive income (loss)
Interest Rate
Swap
Contract
Natural Gas
Forwards
Contracts
Total
$
(439) $
(2,840) $
(3,279)
61
376
437
(5,411)
1,044
(5,350)
1,420
(4,367)
(3,930)
BALANCE at December 31, 2017
$
(2) $
(7,207) $
(7,209)
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive (loss) income
(354)
37
(317)
(1,002)
1,037
(1,356)
1,074
35
(282)
BALANCE at December 31, 2018
$
(319) $
(7,172) $
(7,491)
Other comprehensive (loss) income before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive (loss) income
(711)
175
(536)
1,085
1,063
2,148
374
1,238
1,612
BALANCE at December 31, 2019
$
(855) $
(5,024) $
(5,879)
The components of other comprehensive income/(loss), attributable to the Company, that have been reclassified out of
Accumulated other comprehensive loss consisted of the following:
2019
2018
2017
Affected Line Items on the
Statements of Operations and
Comprehensive Income
Details about other comprehensive income/
(loss) components:
Gains on cash flow hedges:
Interest rate swap contracts
Commodity hedge contracts
Total reclassifications for the period
$
$
175
1,063
1,238
$
$
37
1,037
1,074
$
$
376
1,044
1,420
Interest expense
Cost of products sold
12. COMMITMENTS AND CONTINGENCIES
The Company leases and licenses mineral rights from the U.S. Bureau of Land Management, the state of Wyoming, Rock
Springs Royalty Company, LLC (“RSRC”) an affiliate of Occidental Petroleum Corporation (formerly an affiliate of
Anadarko Petroleum Corporation), and other private parties which provide for royalties based upon production volume.
The Company has a perpetual right of first refusal with respect to these leases and license and intends to continue
renewing the leases and license as has been its practice.
The Company entered into a 10 year rail yard switching and maintenance agreement with a third party, Watco Companies,
LLC (“Watco”), on December 1, 2011. Under the agreement, Watco provides rail-switching services at the Company’s
rail yard. The Company’s rail yard is constructed on land leased by Watco from Rock Springs Grazing Association and on
land by which Watco holds an easement from Anadarko Land Corp; the Rock Springs Grazing Association land lease is
renewable every five years for a total period of thirty years, while the Anadarko Land Corp. easement lease is perpetual.
19
The Company has an option agreement with Watco to assign these leases to the Company at any time during the land
lease term. An annual rental of $15 is paid under the easement and an annual rental of $60 is paid under the lease.
The Company entered into two track lease agreements, collectively expiring in 2021, with Union Pacific Company for
certain rail tracks used in connection with the rail yard.
As of December 31, 2019, the total minimum contractual rental commitments under the Company’s various operating
leases, including renewal periods were as follows:
2020
2021
2022
2023
2024
Thereafter
Total
Leased Land
75
$
75
75
75
75
1,200
1,575
$
Track Leases
70
$
33
—
—
—
—
103
$
$
$
Total
145
108
75
75
75
1,200
1,678
Ciner Corp typically enters into operating lease contracts with various lessors for rail cars to transport product to
customer locations and warehouses. Rail car leases under these contractual commitments range for periods from one to
ten years. Ciner Corp's obligations related to these rail car leases are $11,134 in 2020, $8,485 in 2021, $5,568 in 2022,
$2,586 in 2023, $2,255 in 2024 and $4,038 in 2025 and thereafter. Total lease expense allocated to the Company from
Ciner Corp was approximately $11,770, $13,919 and $14,628 for the years ended December 31, 2019, 2018 and 2017,
respectively, and is recorded in cost of products sold.
Purchase Commitments - The Company has both physical and financial natural gas supply contracts to mitigate volatility
in the price of natural gas. As of December 31, 2019, these contracts totaled approximately $37,500 for the purchase of a
portion of our natural gas requirements over approximately the next five years. The supply purchase agreements have
specific commitments of $16,095 in 2020, $9,974 in 2021, $6,213 in 2022, $4,317 in 2023 and $864 in 2024. The
Company has a separate contract that expires in 2021 and renews annually thereafter, for transportation of natural gas
with an average annual cost of approximately $3,928 per year.
Legal and Environmental - From time to time we are party to various claims and legal proceedings related to our business.
Although the outcome of these proceedings cannot be predicted with certainty, management does not currently expect any
of the legal proceedings we are involved in to have a material effect on our business, financial condition and results of
operations. We cannot predict the nature of any future claims or proceedings, nor the ultimate size or outcome of existing
claims and legal proceedings and whether any damages resulting from them will be covered by insurance.
Litigation Settlement- On February 2, 2016, amended on January 3, 2017, Ciner Wyoming filed suit against RSRC in the
Third Judicial District Court in Sweetwater County, Wyoming, Case No. C-16-77-L, seeking, among other things, to
recover approximately $32,000 in royalty overpayments. The royalty payments arose under our license with RSRC, an
affiliate of Occidental Petroleum Corporation, to mine sodium minerals from lands located in Sweetwater County,
Wyoming (“License”). The License sets the applicable royalty rate based on a most favored nation clause, where either
the royalty rate is set at the same royalty rate we pay to other licensors in Sweetwater County for sodium minerals, or, if
certain conditions are met, the royalty rate is set by the rate paid by a third party to an affiliate of Occidental Petroleum
Corporation under a separate license. In the lawsuit, we claimed that RSRC had, for at least the last ten years, been
charging an arbitrarily high royalty rate in contradiction of the License terms. In addition, we sought a modification of the
expiration term of the License land-lease between Ciner Wyoming and RSRC to those terms granted to other licensors in
accordance with the most favored nation clause.
On June 28, 2018, RSRC and Ciner Wyoming signed a Settlement Agreement and Release (the “Settlement Agreement”)
which among other things (i) required RSRC to pay Ciner Wyoming $27,500 which was received on July 2, 2018, and (ii)
20
concurrently amended selected sections of the License land-lease including among other things, (a) extension of the term
of the License Agreement to July 18, 2061 and for so long thereafter as Ciner Wyoming continuously conducts operations
to mine and remove sodium minerals from the licensed premises in commercial quantities; and (b) revises the production
royalty rate for each sale of sodium mineral products produced from ore extracted from the licensed premises at the
royalty rate of eight percent (8%) of the net sales of such sodium mineral products. There are no unresolved conditions or
uncertainties associated with the Settlement Agreement and management determined the $27,500 settlement payment was
related to the historical overpayment of royalties. The $27,500 litigation settlement was realized in the second quarter of
2018.
Off-Balance Sheet Arrangements - We have a self-bond agreement with the Wyoming Department of Environmental
Quality (“WDEQ”) under which we commit to pay directly for reclamation costs at our Green River, Wyoming plant site.
The amount of the bond was $36,200 and $32,900 as of December 31, 2019 and December 31, 2018, respectively, the
former of which is the amount we would need to pay the State of Wyoming for reclamation costs if we cease mining
operations currently. The amount of this self-bond is subject to change upon periodic re-evaluation by the Land Quality
Division. In May 2019, the State of Wyoming enacted legislation that limits our and other mine operators’ ability to self-
bond, which will require the Company to seek other acceptable financial instruments to provide additional assurance for
its reclamation obligations. The Company expects to provide such assurances by securing a third-party surety bond no
later than November 2020. As of the date of this Report, the Company anticipates that any such impact on the Company’s
net income and liquidity will be limited. The amount of such surety guarantee is subject to change upon periodic re-
evaluation by the WDEQ’s Land Quality Division.
13. AFFILIATE TRANSACTIONS
Ciner Corp is the exclusive sales agent for the Company and through its membership in ANSAC, Ciner Corp is
responsible for promoting and increasing the use and sale of soda ash and other refined or processed sodium products
produced. ANSAC operates on a cooperative service-at-cost basis to its members such that typically any annual profit or
loss is passed through to the members. On November 9, 2018, Ciner Corp delivered a notice to terminate its membership
in ANSAC. See Note 2 - Nature of Operations and Summary of Significant Accounting Policies - ANSAC Exit for more
information regarding the notice to terminate.
All actual sales and marketing costs incurred by Ciner Corp are charged directly to the Company. Selling, general and
administrative expenses also include amounts charged to the Company by Ciner Corp principally consisting of salaries,
benefits, office supplies, professional fees, travel, rent and other costs of certain assets used by the Company. Ciner Corp
has agreed to provide the Company with certain corporate, selling, marketing, and general and administrative services, in
return for which the Company has agreed to pay Ciner Corp an annual management fee and reimburse Ciner Corp for
certain third-party costs incurred in connection with providing such services. In addition, under the limited liability
company agreement of the Company, as amended, the Company reimburses the Partnership for employees who operate
the Company’s assets and for support provided to the Company. These transactions do not necessarily represent arm's
length transactions and may not represent all costs if the Company operated on a standalone basis.
The total selling, general and administrative costs charged to the Company by affiliates for the years ended December 31,
2019, 2018 and 2017 were as follows:
Ciner Corp
ANSAC (1)
Ciner Resources
Total selling, general and administrative expenses - affiliates
2019
2018
2017
$
$
14,233
3,508
663
18,404
$
$
13,728
2,998
972
17,698
$
$
13,549
2,487
484
16,520
(1) ANSAC allocates its expenses to its members using a pro rata calculation based on sales.
21
Cost of products sold includes an allocation of Ciner Corp's rail car lease expense (refer to Note 12) and charges for
logistics services provided by ANSAC. For the years ended December 31, 2019, 2018 and 2017, these ANSAC logistics
costs were $0, $0 and $19,573, respectively. When we elect to use ANSAC to provide freight services for our other non-
ANSAC international sales, ANSAC separately and directly charges the Company for such services. During the year
ended 2019 and 2018 we did not use ANSAC for non-ANSAC international sales. The decrease in freight costs charged
by ANSAC was due to a decrease in non-ANSAC international sales, to CIDT, during the years ended December 31, 2019
and December 31, 2018 when compared to 2017. There were no sales to CIDT during the years ended December 31, 2019
and December 31, 2018, as the previous contract concluded in the 2017 year.
Net sales to affiliates for the years ended December 31, 2019, 2018 and 2017 were as follows:
ANSAC
CIDT
Total
2019
315,847
—
315,847
$
$
2018
253,345
—
253,345
$
$
2017
222,231
82,266
304,497
$
$
As of December 31, 2019 and 2018, the Company had due from/to with affiliates as follows:
ANSAC
CIDT
Ciner Corp
Other
Total
2019
2018
Due from
Affiliates
Due to
Affiliates
Due from
Affiliates
Due to
Affiliates
$
$
53,859
5,468
35,713
75
95,115
$
$
1,614
—
1,423
178
3,215
$
$
48,707
7,116
14,324
212
70,359
$
$
743
—
2,014
86
2,843
The increase in due from Ciner Corp from December 31, 2018 to December 31, 2019 is due to timing of funding of
pension and postretirement plans offered and administered by Ciner Corp.
14. MAJOR CUSTOMERS AND SEGMENT REPORTING
Our operations are similar in geography, nature of products we provide and type of customers we serve. As the Company
earns substantially all of its revenues through the sale of soda ash mined at a single location, we have concluded that we
have one operating segment for reporting purposes. The net sales by geographic area for the years ended December 31,
2019, 2018 and 2017 were as follows:
Domestic
International:
ANSAC
CIDT
Total international
Total net sales
15. REVENUE
2019
206,996
315,847
—
315,847
522,843
$
$
2018
233,414
253,345
—
253,345
486,759
$
$
2017
192,843
222,231
82,266
304,497
497,340
$
$
The Company has one reportable segment and our revenue is derived from the sale of soda ash which is our sole and
primary good and service. We account for revenue in accordance with ASC 606, Revenue from Contracts with
Customers.
Performance Obligations. A performance obligation is a promise in a contract to transfer a distinct good or service to the
customer, and is the unit of account in ASC 606. A contract's transaction price is allocated to each distinct performance
22
obligation and recognized as revenue when, or as, the performance obligation is satisfied. At contract inception, we assess
the goods and services promised in contracts with customers and identify performance obligations for each promise to
transfer to the customer, a good or service that is distinct. To identify the performance obligations, the Company
considers all goods and services promised in the contract regardless of whether they are explicitly stated or are implied by
customary business practices. From its analysis, the Company determined that the sale of soda ash is currently its only
performance obligation. Many of our customer volume commitments are short-term and our performance obligations for
the sale of soda ash are generally limited to single purchase orders.
When performance obligations are satisfied. Substantially all of our revenue is recognized at a point-in-time when
control of goods transfers to the customer.
Transfer of Goods. The Company uses standard shipping terms across each customer contract with very few exceptions.
Shipments to customers are made with terms stated as Free on Board (“FOB”) Shipping Point. Control typically
transfers when goods are delivered to the carrier for shipment, which is the point at which the customer has the ability to
direct the use of and obtain substantially all remaining benefits from the asset.
Payment Terms. Our payment terms vary by the type and location of our customers. The term between invoicing and
when payment is due is not significant and consistent with typical terms in the industry.
Variable Consideration. We recognize revenue as the amount of consideration that we expect to receive in exchange for
transferring promised goods or services to customers. We do not adjust the transaction price for the effects of a
significant financing component, as the time period between control transfer of goods and services and expected payment
is one year or less. At the time of sale, we estimate provisions for different forms of variable consideration (discounts,
rebates, and pricing adjustments) based on historical experience, current conditions and contractual obligations, as
applicable. The estimated transaction price is typically not subject to significant reversals. We adjust these estimates
when the most likely amount of consideration we expect to receive changes, although these changes are typically
immaterial.
Returns, Refunds and Warranties. In the normal course of business, the Company does not accept returns, nor does it
typically provide customers with the right to a refund.
Freight. In accordance with ASC 606, the Company made a policy election to treat freight and related costs that occur
after control of the related good transfers to the customer as fulfillment activities instead of separate performance
obligations. Therefore freight is recognized at the point in which control of soda ash has transferred to the customer.
Revenue disaggregation. In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with
customers into geographical regions. The Company determined that disaggregating revenue into these categories
achieved the disclosure objectives to depict how the nature, timing, amount and uncertainty of revenue and cash flows are
affected by economic factors. Refer to Note 14, “Major Customers and Segment Reporting” for revenue disaggregated
into geographical regions.
Contract Balances. The timing of revenue recognition, billings and cash collections results in billed receivables, unbilled
receivables (contract assets), and customer advances and deposits (contract liabilities).
Contract Assets. At the point of shipping, the Company has an unconditional right to payment that is only dependent on
the passage of time. In general, customers are billed and a receivable is recorded as goods are shipped. These billed
receivables are reported as “Accounts Receivable, net” on the Balance Sheet as of December 31, 2019 and December 31,
2018. There were no contract assets as of December 31, 2019 or December 31, 2018.
Contract Liabilities. There may be situations where customers are required to prepay for freight and insurance prior to
shipment. The Company has elected the practical expedient for its treatment of freight and therefore, such prepayments
23
are considered a part of the single obligation to provide soda ash. In such instances, a contract liability for prepaid
freight will be recorded. For the twelve months ended December 31, 2019, there were no customers that required prepaid
freight. There were no contract liabilities as of December 31, 2019 or as of the date of adoption of ASC 606.
Practical and Expedients Exceptions
Incremental costs of obtaining contracts. We generally expense costs related to sales, including sales force salaries and
marketing expenses, when incurred because the amortization period would have been one year or less. These costs are
recorded within sales and marketing expenses.
Unsatisfied performance obligations. We do not disclose the value of unsatisfied performance obligations for contracts
with an original expected length of one year or less.
16. SUBSEQUENT EVENT
On February 18, 2020, the members of the Board of Managers of Ciner Wyoming, approved a cash distribution to the
members of Ciner Wyoming in the aggregate amount of $14,500. This distribution was paid on February 20, 2020.
******
24
2019 Financial Highlights
Unitholder Information
(in thousands, except per unit)
2019
2018 (1)
2017
2016
2015
For the Years Ended December 31
Total revenues and other income
Asset impairments
Income (loss) from operations
Net income (loss) from continuing operations
Net income from continuing operations
excluding impairments
$ 263,935
$
$
$
148,214
51,321
(25,414)
$ 122,800
Net income (loss) from discontinued operations
$
956
Net income (loss)
$ (24,458)
Per common unit amounts (basic)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Per common unit amounts (diluted)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Distributions paid per common unit
Average number of common
units outstanding - basic
Average number of common
units outstanding - diluted
Net cash provided by (used in)
Operating activities of continuing operations
Investing activities of continuing operations
Financing activities of continuing operations
Free cash flow (2)
Cash flow cushion (2)
Distributable cash flow (2)
Adjusted EBITDA (2)
$
$
$
$
$
$
$
(4.43)
0.08
(4.35)
(4.43)
0.08
(4.35)
2.65
12,260
12,260
$
$
137,319
8,221
$ (253,305)
$ 139,040
$
7,762
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
278,512
$ 246,325
$ 279,244
$ 300,635
18,280
192,538
122,360
140,640
17,687
140,047
7.35
1.42
8.77
5.90
0.86
6.76
1.80
12,244
20,234
178,282
7,607
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,967
176,559
82,485
85,452
6,182
88,667
4.57
0.50
5.06
3.68
0.28
3.96
1.80
12,232
21,950
$
$
$
$
$
$
$
$
$
$
$
$
$
15,861
181,157
90,626
$
378,327
$ (170,699)
$ (260,443)
106,487
$ $117,884
6,266
$
(311,277)
96,892
$ (571,720)
7.28
0.50
7.78
7.28
0.50
7.78
1.80
12,232
12,232
$
$
$
$
$
$
$
(20.80)
(24.94)
(45.75)
(20.80)
(24.94)
(45.75)
2.70
12,232
12,232
112,151
9,807
$
$
80,243
65,057
$
$
144,907
15,805
(6,839)
$ (134,149)
$ (146,373)
$ (166,443)
183,440
16,080
121,324
$
75,970
9,248
$ (29,444)
$
$
$
144,210
(8,339)
157,815
$ 144,933
$ 383,980
$ 199,228
$
230,241
121,958
211,483
$
255,172
$ 235,273
$ 240,553
$
$
$
$
$
Cash, cash equivalents and restricted cash
$
98,265
$ 206,030
26,980
$
39,171
$
40,244
Total assets
$ 1,085,907
$ 1,341,647
$ 1,389,164
$ 1,448,649
$ 1,674,865
Current portion of long-term debt, net
Long-term deb, net
Long-term lease obligations (3)
Class A convertible preferred units
Partners’ capital
$
45,776
$ 470,422
$
3,506
$ 164,587
$ 338,963
$
$
$
$
$
115,184
$
79,740
$
140,037
$
80,745
557,574
$ 729,608
$ 990,234
$ 1,130,696
—
164,587
423,481
$
$
$
—
173,431
265,211
$
$
$
—
—
151,530
$
$
$
—
—
76,336
(1) On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, and all the related amendments to all open contracts using
the modified retrospective method. NRP recognized a $70.5 million cumulative effect of adoption adjustment in the opening balance of partners’ capital on January 1, 2018. Comparative
information for the years ended December 31, 2017, 2016 and 2015 have not been restated and continues to be reported under the standards in effect for those periods.
(2) See “—Non-GAAP Financial Measures” in this Annual Report on Form 10-K form more information.
(3) On January 1, 2019, NRP adopted Accounting Standards Codification (ASC) 842, Leases, and all the related amendments and recognized assets and liabilities on its Consolidated Balance
Sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months.
Partnership Headquarters
1201 Louisiana Street
Suite 3400
Houston, TX 77002
713-751-7507
Regional Offices
Coal and Hard Minerals
5260 Irwin Road
Huntington, WV 25705
Investor Relations
Tiffany Sammis
1201 Louisiana Street
Suite 3400
Houston, TX 77002
713-751-7515
Email: info@nrplp.com
Stock Exchange
Our units are listed on the
New York Stock Exchange
under the symbol NRP.
Independent Auditors
Ernst & Young LLP
5 Houston Center
1401 McKinney St, Suite 2400
Houston, TX 77010
Transfer Agent and Registrar
American Stock Transfer
and Trust Company
Client Operations
6201 15th Avenue
Brooklyn, NY 11219
Website: www.astfinancial.com
Email:help@astfinancial.com
800-937-5449
Website
www.nrplp.com
Information regarding Natural Resource Partners L.P. is located on the partnership’s
website. On the site is operational and financial information as well as all SEC filings and
our corporate governance documents, including our Code of Business Conduct and Ethics,
our Corporate Governance Guidelines and Board of Directors’ Audit Committee Charter.
Requests for copies of the annual report or other data may be made through the website or
by contacting Investor Relations. These requests will be provided free of charge.
Contact NRP Board
We have established procedures for contacting the non-management members of the
NRP Board of Directors. To communicate any concerns or issues to the Board of Directors,
please direct any correspondence to:
Chairman of the CNG Committee
NRP Board of Directors
1201 Louisiana Street, Suite 3400
Houston, TX 77002
888-252-2396
Schedule K-1
Unitholders receive Schedule K-1 packages that summarize their allocable share of the
partnership’s reportable tax items for the calendar year. Generally, these K-1s are available
on NRP’s website no later than mid-March. Unitholders should refer questions regarding
their Schedule K-1 to the following:
Natural Resource Partners L.P.
Tax Package Support
P.O. Box 799060
Dallas, TX 75379-9060
Fax: 1-866-554-3842
Toll Free: 1-888-334-7102
Forward-Looking Statements
Statements included in this annual report 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
COVID-19, capital expenditures and acquisitions, expected commencement dates of
mining, projected quantities of future production by our lessees producing from our
reserves, and projected demand or supply for coal, trona and soda ash that will affect
sales levels, prices and royalties realized by us.
These forward-looking statements speak only as of the date hereof and are made based
upon management’s current plans, expectations, estimates, assumptions and beliefs
concerning future events impacting us and therefore involve a number of risks and
uncertainties, including uncertainties surrounding the COVID-19 pandemic. 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. Please read “Item
1A. Risk Factors” of the Form 10-K for important factors that could cause our actual results
of operations or our actual financial condition to differ.
2019 Annual Report
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Natural Resource Partners L.P.
1201 Louisiana Street, 34th Floor
Houston, Texas 77002
www.nrplp.com
Natural Resource Partners L.P.