2020 Accomplishments
Zero safety incidents
Generated $89 million of
Free Cash Flow
Reduced outstanding debt
by $46 million
Ended the year with
$200 million of liquidity,
consisting of $100 million of
cash and $100 million of
available borrowing capacity
Paid $16.6 million of
distributions to common
unitholders
Reached a favorable
agreement with Foresight
Energy, our largest lessee,
which allowed them to
emerge from bankruptcy and
resulted in $49 million of cash
to NRP in 2020 and will result
in $42 million in 2021
47218natD1R3.indd 4-6
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Natural Resource Partners L.P.
2020 Annual Report
To Our Unitholders
The unprecedented public health and economic challenges of 2020 demonstrated that
we have the right strategy in place to create unitholder value. While COVID-19 ravaged
the world, our partnership continued to operate safely, generate free cash flow, pay
down debt, and build liquidity. All of this was accomplished while working remotely
as part of our plan to prioritize the health and safety of our people.
Business Highlights
Our Coal Royalty & Other segment generated $126 million of Free Cash Flow in 2020.
Our metallurgical properties, which are a source of coal used to manufacture steel,
generated approximately 70% of our coal royalty revenues.
Our Soda Ash segment consists of a 49% equity investment in Ciner Wyoming, one of
the lowest cost producers of natural soda ash in the world. Global demand for soda ash,
which is a key commodity used in the production of glass, was negatively impacted by
the COVID-19 pandemic, causing Ciner to suspend cash distributions early in the year.
As a result, we received only $14 million of Free Cash Flow from Soda Ash in 2020.
While we do not know when regular distributions will recommence, the rebound in
global economic activity and resulting increase in soda ash demand allowed Ciner
Wyoming to resume pre-pandemic levels of production by year end.
47218natD2R1.indd 1
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Looking Ahead
In addition to actively managing our legacy business segments, we have also been
working to identify alternative revenue sources across our large portfolio of land, mineral
and timber assets. The types of opportunities we are exploring include the sequestration
of CO2 underground and in standing timber, and the generation of electricity using
geothermal, wind and solar energy. While we do not expect these activities to generate
significant cash flow in the immediate future, we believe our large ownership footprint
throughout the United States will provide opportunities to create value in this regard with
minimal capital investment by NRP.
NRP’s demonstrated ability to continue generating free cash flow, permanently reducing
our outstanding debt, and paying unitholder distributions during the COVID-19 downturn
is a testament to the transformative actions taken in recent years to right-size the business.
Over the last five years, NRP has paid down over $900 million of debt, paid $115 million of
common unitholder distributions, and worked to solidify our capital structure and ensure
strong liquidity. We remain steadfast in our commitment to focus on maximizing unitholder
value by continuing these efforts. Thank you to our stakeholders who supported our team
through the years and thank you for your continued support of NRP.
Corbin J. Robertson, Jr.
Craig Nunez
Chairman and Chief Executive Officer
President and Chief Operating Officer
2
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4/29/21 3:25 PM
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, 2020 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: 001-31465
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
Non-accelerated Filer
☐
☐
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its
internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public
accounting firm that prepared or issued its audit report ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yes ☐ No ☒
The aggregate market value of the common units held by non-affiliates of the registrant on June 30, 2020, was $109 million based on a
closing price on that date of $12.19 per unit as reported on the New York Stock Exchange.
Documents incorporated by reference: None.
Table of Contents
TABLE OF CONTENTS
Cautionary Statement Regarding Forward-Looking Statements
Risk Factors Summary
Items 1. and 2. Business and Properties
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
PART I
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
i
ii
ii
1
16
32
32
32
33
33
34
50
51
90
90
92
93
99
102
104
111
114
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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: the effects of the global COVID-19 pandemic; 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.
RISK FACTORS SUMMARY
We are subject to a variety of risks and uncertainties, including risks related to our business, risks related to our
indebtedness, risks related to our common stock and certain general risks, which could have a material adverse effect on our
business, financial condition, results of operations and cash flows. Risks that we deem material are described under “Risk
Factors” in Item 1A of this report. These risks include, but are not limited to, the following:
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.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business
prospects.
The ongoing COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition,
results of operations, and ability to make cash distributions to unitholders will depend on future developments, which are
highly uncertain and cannot be predicted.
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.
Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on
Ciner Wyoming’s ability to resume distributions to us.
• We derive a large percentage of our revenues and other income from a small number of coal lessees.
•
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.
• Mining operations are subject to operating risks that could result in lower revenues to us.
•
•
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.
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.
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Table of Contents
•
•
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.
If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.
• We have limited approval rights with respect to the management of our Ciner Wyoming soda ash joint venture, including
with respect to cash distributions and capital expenditures. In addition, 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.
•
•
•
•
•
•
•
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.
Ciner Wyoming’s deca stockpiles will substantially deplete by 2024, and its production rates will decline approximately
200,000 short tons per year if further investments are not made.
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 resume distributions to us.
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.
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, we expect to cease reporting coal and hard mineral reserves pursuant to
new SEC rules that will be effective for us beginning with the year ending December 31, 2021.
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.
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.
Risks Related to Our Structure
•
•
Unitholders may not be able to remove our general partner even if they wish to do so.
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.
• 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 has a limited call right that may require unitholders to sell their units at an undesirable time or price.
Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to
unitholders.
Conflicts of interest could arise among our general partner and us or the unitholders.
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.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Tax Risks to Common 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.
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Table of Contents
•
•
•
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.
Certain federal income tax preferences currently available with respect to coal exploration and development may be
eliminated as a result of future legislation.
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.
• 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.
•
•
•
•
•
•
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.
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.
Tax gain or loss on the disposition of our common units could be more or less than expected.
Our 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.
Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning
our units.
• 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.
• 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.
• 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.
•
•
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.
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.
General Risks
•
•
Our business is subject to cybersecurity risks.
The ongoing COVID-19 pandemic has adversely affected our business and may continue to do so.
Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may have an
adverse effect on our business, financial condition, results of operations, and cash flows.
iv
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 Wyoming mines trona and processes it into soda ash
that is sold both domestically and internationally into the glass and chemicals industries.
We expect royalties generated from coal mining operations on our properties and our interest in the Ciner Wyoming soda
ash business to generate the substantial majority of our cash flow over the next years. However, over the past year, we have
been evaluating our existing portfolio of assets for opportunities to generate alternative sources of revenues without significant
capital investment by us. For example, our surface and mineral acreage owned across the United States may contain geologic
formations that are suitable for the long-term sequestration and storage of carbon. To the extent a viable carbon sequestration
project is developed on or near our property, we may be able to lease that property as storage in exchange for rent payments.
We are also exploring opportunities to lease our surface acreage for renewable energy projects, such as solar arrays and wind
farms. In addition, we are assessing our forest timber assets for carbon sequestration project potential whereby we would obtain
and sell carbon offset credits in exchange for agreements for long-term forest preservation. There can be no assurance, however,
that any of these potential projects will succeed or generate substantial cash flow to NRP.
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.
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Table of Contents
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.
Segment and Geographic Information
The amount of 2020 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—Item 8. Financial Statements
and Supplementary Data—Note 7. 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
$
$
129,592
10,728
140,320
92%
8%
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.
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Coal Reserves and Production Information
The following table presents coal reserves information as of December 31, 2020 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
206,097
699,977
40,699
946,773
209,981
—
—
3,018
242,821
17,993
263,832
5,074
161,817
1,000
209,115
942,798
58,692
1,210,605
215,055
161,817
1,000
1,156,754
431,723
1,588,477
(1)
In excess of 80% 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, 2020:
(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
148,661
536,142
40,318
725,121
215,055
161,817
1,000
60,454
406,656
18,374
485,484
—
—
—
209,115
942,798
58,692
1,210,605
215,055
161,817
1,000
1,102,993
485,484
1,588,477
(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.
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The following table presents the sulfur content and the typical quality of our coal reserves by major coal region as of
December 31, 2020:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
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
(%)
46,116
46,316
1,001
161,798
209,115
430,097
658,448
238,721
45,629
942,798
30,386
32,511
23,591
2,590
58,692
Total Appalachia Basin
506,599
737,275
263,313
210,017
1,210,605
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total
—
—
—
—
2,152
212,903
215,055
161,817
1,000
—
—
—
—
161,817
1,000
506,599
900,092
265,465
422,920
1,588,477
12,902
13,227
13,394
13,179
11,534
8,800
6,678
2.24
0.91
1.00
1.14
3.17
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, 2020:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
Total Appalachia Basin
Illinois Basin
Northern Powder River Basin
Total
Type of Coal
Thermal
Metallurgical
Total
267
1,157
143
1,567
3,381
1,738
6,686
380
8,954
746
10,080
—
—
10,080
647
10,111
889
11,647
3,381
1,738
16,766
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.
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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). 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. The new rules contain exceptions that allow royalty companies, such as NRP, to
omit information that they lack access to and cannot obtain without incurring an unreasonable burden or expense. As a royalty
company, we do not have access to a substantial amount of information that will be required to prepare the technical reports
used to determine reserves under the new rules, and we will not be able to obtain such information without unreasonable burden
or expense. Accordingly, we expect that we will rely on the royalty company exceptions and will therefore cease to report coal
and other hard mineral reserves beginning with the year ending December 31, 2021. 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, we expect to cease reporting coal and hard mineral
reserves pursuant to new SEC rules that will be effective for us beginning with the year ending December 31, 2021."
Major Coal Producing Properties
The following table provides a summary of our significant coal royalty properties by sales volumes for 2020 and is
followed by additional information for each property:
Region
Property/Lease Name
Operator(s)
Coal Type
2020 Sales Volumes
(Millions of Tons)
Appalachia Basin
Central
Central
Central
Central
Southern
Illinois Basin
Illinois Basin
Illinois Basin
Northern Powder
River Basin
Contura-CAPP (VA)
Alpha Metallurgical Resources Inc.
Coal Mountain
CM Energy Properties, LP
Aracoma
Elk Creek
Oak Grove
Macoupin
Williamson
Hillsboro
Alpha Metallurgical Resources Inc.
Ramaco Resources, Inc.
Crimson Oak Grove Resources LLC
Foresight Energy Resources LLC
Foresight Energy Resources LLC
Foresight Energy Resources LLC
Western Energy
Rosebud Mining, LLC
Met
Met
Met
Met
Met
Thermal
Thermal
Thermal
Thermal
3.7
0.7
1.1
0.9
0.7
0.4
1.0
2.0
1.7
Appalachia Basin—Central Appalachia
Contura-CAPP (VA). The Contura-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties,
Virginia. In 2020, approximately 3.7 million tons were sold from this property, substantially all of which was metallurgical
coal. We lease this property to subsidiaries of Alpha Metallurgical Resources Inc. ("Alpha Metallurgical Resources") (formerly
Contura Energy, Inc.). 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 2020, approximately 0.7
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 1.1 million tons of coal,
substantially all of which is metallurgical coal, were sold in 2020 from this property. We lease this property to a subsidiary of
Alpha Metallurgical Resources. 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.
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Elk Creek. The Elk Creek property is located in Logan and Wyoming Counties, West Virginia. In 2020, approximately
0.9 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.
Appalachia Basin—Southern Appalachia
Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2020, approximately 0.7 million tons
of metallurgical coal were sold from this property. We lease this property to Crimson Oak Grove Resources LLC (formerly
Murray Metallurgical Coal Holdings, LLC). 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.
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 Resources LLC ("Foresight"). In 2020, approximately 0.4 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. Production at the Macoupin mine was temporarily ceased
in March 2020.
Williamson. The Williamson property is located in Franklin and Williamson Counties, Illinois. This property is under
lease to Williamson Energy, a subsidiary of Foresight. In 2020, approximately 1.0 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 2020, we also received overriding royalties from approximately 0.2 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. This property had been idled from March 2015 until production resumed in January
2019. In 2020, approximately 2.0 million tons of thermal coal were sold from this property. Production comes from a longwall
mine. 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. See "—Coal Transportation and Processing Assets" below for
additional information on these assets.
Master Agreement. On June 30, 2020, we and Foresight entered into the Master Amendment and Supplement to Coal
Mining and Transportation Lease Agreements and Parent Guaranty (the “Master Agreement”) in connection with Foresight’s
emergence from bankruptcy. All contracts and agreements existing prior to the bankruptcy filing were assumed by Foresight in
the bankruptcy and continue post-bankruptcy pursuant to their terms, except as amended by the Master Agreement.
Pursuant to the Master Agreement, Foresight made fixed cash payments of $48.75 million to NRP in 2020 and will make
$42.0 million in cash payments to NRP in 2021 to satisfy all obligations arising out of the existing various coal mining leases
and transportation infrastructure fee agreements between NRP and Foresight for calendar years 2020 and 2021. Beginning in
January 2022, Foresight’s payment obligations will be calculated in accordance with the provisions of the various existing
agreements, except as described below with respect to Foresight’s Macoupin mine.
Production at the Macoupin mine was temporarily ceased in March 2020. Pursuant to the Master Agreement, Foresight is
no longer obligated to make royalty, transportation fee, or quarterly minimum payments to us under the Macoupin coal mining
lease and transportation agreements. Foresight will pay an annual Macoupin fee of $2.0 million to NRP each year through 2023.
The amounts paid for 2020 and payable for 2021 are included in the fixed amounts discussed in the paragraph above. Foresight
also forfeited its right to recoup all previously paid but unrecouped minimum payments with respect to the Macoupin mine. At
all times that the Macoupin mine remains in temporary cessation of production, Foresight will take reasonable actions to
preserve, protect, and store the equipment, infrastructure, and property located at the mine.
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Beginning January 1, 2024, we may at any time elect to cause Foresight to transfer the Macoupin mine and all associated
equipment and permits to us for no consideration. If we make this election, we will assume all liabilities associated with the
Macoupin mine. Also beginning January 1, 2024, Foresight may at any time elect to offer to sell the Macoupin assets to us for
$1.00. If we accept Foresight’s offer, we will assume all liabilities associated with the Macoupin mine. If we do not accept
Foresight’s offer, Foresight may proceed to permanently seal the Macoupin mine and conduct all reclamation activities. To the
extent the elections described above are not made, Foresight will continue to pay the annual $2.0 million fee to NRP each year
that the mine remains in temporary cessation of production. In addition, Foresight may determine at any time to recommence
operations at the Macoupin mine, at which time we and Foresight will negotiate in good faith to enter into new coal mining
lease and transportation agreements.
Northern Powder River Basin
Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2020,
approximately 1.7 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.
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'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 and
are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we
subcontract to a subsidiary of Foresight. 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. 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 and we collect minimums and throughput fees. We recorded $8.8 million in revenue related to our coal
transportation and processing assets during the year ended December 31, 2020.
Other Coal Royalty and Other Segment Assets
Until mid-2020, we owned a 51% interest in BRP LLC, a joint venture with International Paper. In 2020, we bought
International Paper’s 49% interest in BRP LLC and now own 100%. Through BRP LLC, we own approximately 10 million
mineral acres in over 30 states in the U.S. We own various mineral rights for lease encompassing oil and gas prospects, coal
and coal bed methane rights, copper and other metals, aggregates, water, and geothermal. While the vast majority of the
approximately 10 million acres remain largely undeveloped, we have an ongoing program to identify additional opportunities to
lease these minerals to operating parties or otherwise monetize these assets.
As of December 31, 2020, we also owned aggregates mineral rights 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 frac sand at operations in Wisconsin and Texas and sand and gravel reserves in Washington. During 2020,
we received $1.7 million in aggregates royalty revenues, including overriding royalty revenues.
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Soda Ash Segment
We own a 49% non-controlling equity interest in Ciner Wyoming. Ciner Resources LP, our operating partner ("Ciner
Resources"), controls and operates Ciner Wyoming. Ciner Wyoming mines trona and processes it into soda ash that is sold both
domestically and internationally into the glass and chemicals industries. Ciner Resources is a publicly traded master limited
partnership that depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders. 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. 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. 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.
During 2020, Ciner Wyoming suspended cash distributions to its members due to adverse developments in the soda ash market
resulting from the COVID-19 pandemic. Distributions remain suspended and may continue to be suspended until the soda ash
markets improve.
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 2,300 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.
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 over 58,000 short tons of processed soda ash at any given time. The facility
is in good working condition and has been in service for more than 50 years.
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 2024 and that production rates will decline approximately 200,000 short tons per year if that production capacity
is not replaced.
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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, 2020, Ciner Wyoming shipped approximately 97% of its soda ash to its customers initially via a
single rail line owned and controlled by Union Pacific Railroad Company. 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. A leased fleet of more than 2,200
hopper cars serve as dedicated modes of shipment to Ciner Wyoming's domestic customers. For export, soda ash is shipped on
unit trains consisting of approximately 100 cars to two primary ports located in Longview, Washington and Portland, Oregon.
From these ports, the soda ash is loaded onto ships for delivery to ports all over the world. Until 2021, American Natural Soda
Ash Corporation ("ANSAC") provided logistics and support services for all of Ciner Wyoming’s export sales. For domestic
sales, Ciner Resources Corporation ("Ciner Corporation") provides similar services. Ciner Corporation is the parent company of
Ciner Wyoming Holding Co. (“Ciner Holding”), which in turn is the sole member of the general partner of our operating
partner, Ciner Resources.
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. Prior to 2021, Ciner Wyoming’s largest customer was ANSAC, which
bought soda ash (through Ciner 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 45% of Ciner Wyoming’s net
sales in 2020. 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 Corporation, on Ciner Wyoming’s behalf, negotiates directly with, and Ciner
Wyoming exports to, customers in markets not served by ANSAC.
As part of its strategic initiative to gain better direct access and control of international customers and logistics and the
ability to leverage the expertise of the global Ciner Group, the world’s largest natural soda ash producer, Ciner Corporation
delivered a notice to terminate its membership in ANSAC in 2019. The termination was expected to be effective as of the end
of day on December 31, 2021. In July 2020, Ciner Corporation entered into an agreement with ANSAC and its other members
that, among other things, terminated Ciner Corporation’s membership in ANSAC effective as of the end of the day on
December 31, 2020, a year earlier than previously announced. For a limited period after December 31, 2020, Ciner Corporation
will continue to sell, at substantially lower volumes, product to ANSAC for export sales purposes, with a fixed rate per ton
selling, general and administrative expense, and will also purchase a limited amount of export logistics services.
Effective January 1, 2021, Ciner Corporation is managing Ciner Wyoming’s export sales and marketing efforts and is
leveraging the distributor network established by the global Ciner Group. Ciner Corporation is also independently reviewing
current and potential distribution partners to optimize Ciner Wyoming’s global sales. Through Ciner Corporation, Ciner
Wyoming has obtained its own international sales arrangements for 2021, obtained third-party export port services, and
chartered and executed its own international voyages. 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.
For customers in North America, Ciner Corporation 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 “take or pay” arrangements with its customers, substantially all sales are made pursuant to
written agreements and not through spot sales. In 2020, Ciner Wyoming had more than 70 domestic customers and has had
long-term relationships with the majority of its customers.
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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, 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
pursuing the related permits and detailed cost analysis pursuant to the basic design. When considering the significant
investment required by this expansion and the infrastructure improvements designed to increase overall efficiency, combined
with the COVID-19 pandemic’s negative impact on Ciner Wyoming’s financial results, Ciner Wyoming has reprioritized the
timing of the significant expenditure items in order to increase financial and liquidity flexibility until it has more clarity and
visibility into the ongoing impact of the COVID-19 pandemic on its business. 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 delay of Ciner Wyoming’s resumption of cash distributions to its members.
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, 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 and its subsidiaries, with total revenues of $35.7 million in
2020 from all of their mining operations, including transportation and processing services revenues, coal overriding royalty
revenues and wheelage revenues. In June 2020, we entered into lease amendments with Foresight pursuant to which Foresight
agreed to pay us fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and
transportation infrastructure fee agreements between us and Foresight for calendar years 2020 and 2021. We also have a
significant concentration of revenues from Alpha Metallurgical Resources, with total revenues of $33.2 million in 2020 from
several different mining operations, including wheelage revenues. For additional information on significant customers, refer to
"Item 8. Financial Statements and Supplementary Data—Note 14. 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.
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.
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Title to Property
We owned substantially all of our coal and aggregates reserves in fee as of December 31, 2020. 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.
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.
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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 was challenged by public health groups, environmental groups,
states, municipalities, industry groups, and power providers. The legal challenges were consolidated as American Lung Assoc.
v. EPA before the D.C. Circuit Court of Appeals. Dozens of parties and over 170 amici filed briefs on the merits, and oral
argument was held before a three-judge panel in October 2020. In January 2021, the D.C. Circuit issued a written opinion
holding that the ACE Rule was based on EPA’s “erroneous legal premise” that when it determines the “best system of emission
reduction” for existing sources, the Clean Air Act mandates that EPA may only consider emission reduction measures that can
be applied at and/or to a stationary source (often referred to as “inside-the-fence” measures). The Court vacated and remanded
the rule to EPA for further consideration in light of its opinion, which will now occur under the Biden administration.
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
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2017, the court granted EPA’s motion to hold the litigation in abeyance while EPA reviews the rule. In December 2018, EPA
issued a proposed rule revising the best system of emission reduction (“BSER”) for newly constructed coal-fired electric
generating units, among other changes, to replace the 2015 rule. In a status report filed with the Court on January 15, 2021,
EPA requested that the case remain in abeyance until after the transition to the Biden administration.
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. In January 2021, President Biden announced that the United
States is rejoining 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.” The new rule (the Navigable Waters
Protection Rule) took effect in June 2020. In most of the pending legal challenges to the 2015 WOTUS rule, the petitioners
filed amended complaints to include allegations challenging the 2020 rule. In addition, various industry groups, environmental
groups, and states filed new legal challenges to the 2020 rule. Currently, legal challenges to the 2020 rule are pending in at least
twelve federal district courts. However, the 2020 rule is currently in effect everywhere in the U.S. except Colorado, where a
federal district court issued a preliminary injunction preventing the rule from taking effect. There are motions for preliminary
injunctions pending in at least two other courts and cross-motions for summary judgment pending in at least one court.
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 in March 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, 2020, affiliates of our general partner employed 54 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 pay distributions on our common
and preferred units under certain circumstances. The indenture governing our 2025 parent company notes restricts us from
paying more than one-half of the quarterly distribution on our preferred units in cash if our consolidated leverage ratio exceeds
3.75x. Our consolidated leverage ratio has risen since the onset of the COVID-19 pandemic and rose above 3.75x during the
third quarter of 2020, and we began paying one-half of the required quarterly distribution in kind through the issuance of
additional preferred units (“PIK units”) with respect to such quarter. To the extent our leverage ratio continues to exceed 3.75x,
which we expect for the foreseeable future, we will be required to continue to pay one-half of the required preferred
distributions in PIK units and will be unable to redeem any PIK units until our consolidated leverage ratio falls below 3.75x.
Distributions on the outstanding PIK units will accrue and accumulate at 12% per year until such PIK units are redeemed.
Under our partnership agreement, to the extent any PIK units are 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.
In addition, 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.
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 11. Debt, Net."
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business
prospects.
As of December 31, 2020, we and our subsidiaries had approximately $477.9 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;
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•
•
•
•
•
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;
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 $40 million due thereunder during 2021. 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 late 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 11. Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net.”
The ongoing COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition,
results of operations, and ability to make cash distributions to unitholders will depend on future developments, which are
highly uncertain and cannot be predicted.
The ongoing COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created
significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and
the institution of quarantining and other restrictions on movement in many communities and global trading markets. Coal
markets faced substantial challenges prior to the pandemic, and widespread increases in unemployment and decreases in
electricity and steel demand further reduced demand and prices for coal. In addition, demand for and prices of soda ash
decreased, as global manufacturing slowed. If the reduced demand for and prices of coal and/or soda ash continue for a
prolonged period, our financial condition, results of operations, and cash distributions to unitholders may be materially and
adversely affected. Our board of directors determined to suspend cash distributions to our common unitholders with respect to
the first quarter of 2020 in order to preserve liquidity due to uncertainties created by the pandemic. To the extent our board of
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directors deems necessary, it may determine to suspend cash distributions in future quarters as a result of the pandemic. In
addition, Ciner Wyoming suspended cash distributions to its members in 2020 due to adverse effects of the pandemic on the
global and domestic soda ash markets.
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 ongoing
COVID-19 pandemic;
weather conditions; and
the effect of worldwide energy conservation measures.
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 year ended December 31, 2020, we recorded impairment charges of
approximately $136 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.
Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Ciner
Wyoming’s ability to resume distributions to its members and 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. In 2020, Ciner Wyoming suspended distributions to
its members as a result of the adverse impact of the COVID-19 pandemic on global soda ash markets. Historically, the global
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market and, to a lesser extent, the domestic market for soda ash has 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 the COVID-19 pandemic, worldwide and regional economic and political conditions impacting supply and
demand. In addition, the impact of the Ciner Corporation exit from ANSAC and Ciner Wyoming’s transition to the utilization
of Ciner Group’s global distribution network for some of its export operations beginning 2021 could affect prices received for
export sales. 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 Ciner Wyoming’s ability to resume distributions to its members and on our results
of operations.
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 of
Foresight’s mining operations, which accounted for approximately 26% of our total revenues in 2020. Foresight is required to
pay us a fixed amount of $42.0 million during 2021. We also own significant interests in several of Alpha Metallurgical
Resource's mining operations, which accounted for approximately 24% of our total revenues in 2020. 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 bankruptcy laws 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.
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;
• 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
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and reclamation 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 in the United States, and
internationally and 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 are ongoing efforts 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 ongoing pressure on 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 both general liability and director and officer 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.
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;
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
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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.
We have limited approval rights with respect to the management of our Ciner Wyoming soda ash joint venture, including
with respect to cash distributions and capital expenditures. In addition, 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. During 2020, Ciner Wyoming suspended quarterly cash distributions to its members due to adverse developments
in the soda ash market resulting from the COVID-19 pandemic. Distributions remain suspended and may continue to be
suspended until the soda ash markets improve. In February 2021, Ciner Resources was informed that an event of default
currently exists under a loan to certain non-U.S. companies in the global Ciner Group. While the equity interests in Ciner
Wyoming and Ciner Resources are not pledged as security for that loan, the equity interests in in Ciner Holding (the sole
member of the general partner of Ciner Resources) and in Ciner Corporation (the parent company of Ciner Holding) are
pledged as collateral to the lenders under that loan agreement. Accordingly, unless that event of default is cured or otherwise
waived by the requisite number of lenders, the lenders could foreclose on the applicable collateral, which would result in a
change of control of Ciner Resources. Although such a change of control would not result in an event of default under the Ciner
Wyoming credit agreement, any such change in ownership could, among other consequences, have a material adverse effect on
Ciner Wyoming’s business, financial condition, results of operations, and on our relationship with our soda ash joint venture
operating partner.
In addition, we are ultimately responsible for operating the transportation infrastructure at Foresight’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.
In July 2020, ANSAC and its members entered into an agreement that, among other things, terminated Ciner
Corporation’s membership in ANSAC effective as of December 31, 2020, a year earlier than previously announced. For a
limited period after December 31, 2020, Ciner Corporation. will continue to sell, at substantially lower volumes, product to
ANSAC for export sales purposes, with a fixed rate per ton selling, general and administrative expense, and will also purchase a
limited amount of export logistics services. ANSAC has historically been Ciner Wyoming’s largest customer for the years
ended December 31, 2020, 2019 and 2018, accounting for approximately 45%, 60% and 52%, respectively, of its net sales.
Without the ANSAC membership, 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. As a result Ciner
Wyoming’s business, results of operations and financial condition could be adversely affected.
Ciner Wyoming’s deca stockpiles will substantially deplete by 2024, and its production rates will decline approximately
200,000 short tons per year if further investments are not made.
In 2024, Ciner Wyoming’s deca stockpiles will be substantially depleted. Without adding additional capacity, Ciner
Wyoming's production rates will decline approximately 200,000 short tons, which would further impact Ciner Wyoming's
profitability. While Ciner Wyoming is currently evaluating an expansion project that would offset this decline as well as
provide additional soda ash production above current rates, there is no guarantee that any such investments will be executed
successfully or in a timely manner to enable Ciner Wyoming to maintain its current rates of production.
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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 resume distributions to us.
In 2019, Ciner Wyoming announced a significant capacity expansion capital project intended to increase production levels
to up to 3.5 million tons of soda ash per year. When considering the significant investment required by this expansion and the
infrastructure improvements designed to increase overall efficiency, combined with the COVID-19 pandemic’s negative impact
on Ciner Wyoming’s financial results, Ciner Wyoming has reprioritized the timing of the significant expenditure items in order
to increase financial and liquidity flexibility until it has more clarity and visibility into the ongoing impact of the COVID-19
pandemic on its business. 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 delay of
Ciner Wyoming’s resumption of cash distributions to its members, which in turn could have a material adverse effect on us.
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, 2020, Ciner Wyoming shipped
approximately 97% 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, we expect to cease reporting coal and hard mineral reserves pursuant to
new SEC rules that will be effective for us beginning with the year ending December 31, 2021.
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;
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•
•
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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.
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). The new rules contain exceptions that
allow royalty companies, such as NRP, to omit information that they lack access to and cannot obtain without incurring an
unreasonable burden or expense. As a royalty company, we do not have access to a substantial amount information that will be
required to prepare the technical reports used to determine reserves under the new rules, and we will not be able to obtain such
information without unreasonable burden or expense. Accordingly, we expect that we will rely on the royalty company
exceptions and will therefore cease to report coal and other hard mineral reserves beginning with the year ending December 31,
2021.
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.
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.
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:
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•
•
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;
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;
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•
•
•
•
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. Members of Congress
have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect
publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.
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
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the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a
partnership in the future.
Any modification to the U.S. federal income tax laws and interpretation thereof may or may not be retroactively applied
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 changes or other proposals will
ultimately be enacted. Any 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.
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 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.
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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, subject to the exceptions in the Coronavirus Aid, Relief, and Economic Security
Act (the "CARES Act," discussed below), 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
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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 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.
For our 2020 taxable year, the CARES Act increases the 30% adjusted taxable income limitation to 50%, unless we elect
not to apply such increase. For purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute
our 2020 adjusted taxable income with our 2019 adjusted taxable income, which may result in a greater business interest
expense deduction. In addition, unitholders may treat 50% of any excess business interest allocated to them in 2019 as
deductible in the 2020 taxable year without regard to the 2020 business interest expense limitations. The remaining 50% of such
unitholder’s excess business interest is carried forward and subject to the same limitations as other taxable years.
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. 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. While the
determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s
liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly
traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the
applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share
of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an
interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that
date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Prospective foreign
unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
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.
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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 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.
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General Risks
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.
The ongoing COVID-19 pandemic has adversely affected our business and may continue to do so.
The COVID-19 pandemic may also have the effect of heightening many of the other risks described elsewhere in this Item
1A, “Risk Factors.” The extent to which the COVID-19 pandemic adversely affects our business, results of operations, and
financial condition will depend on future developments, which remain highly uncertain and cannot be predicted, including the
scope and duration of the pandemic and actions taken by governmental authorities and other third parties in response to the
pandemic.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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.
In November 2019, the District Court of Harris County, Texas, 157th Judicial District, issued a ruling in the contingent
consideration payment dispute that Anadarko Holding Company and its subsidiary, Big Island Trona Company (together,
"Anadarko") brought against us in July 2017. The Trial Court ruled in our favor in all respects and ordered that Anadarko take
nothing. Anadarko did not appeal the trial court ruling, and accordingly this lawsuit was concluded in the first quarter of 2020
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 March 8, 2021, there were
approximately 10,655 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, 2020. 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
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(a)
(b)
(c)
—
n/a
—
—
n/a
—
415,445 (1)
n/a
415,445
(1) As of December 31, 2020, 355,362 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
Omitted.
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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").
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.
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 and cash flow used in acquisition costs classified as investing or financing
activities. 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.
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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 investing or financing
activities, one-time beneficial items, mandatory Opco debt repayments, preferred unit distributions and redemption of PIK units
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.
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 11. 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.
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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 Wyoming mines trona and processes it into soda ash
that is sold both domestically and internationally into the glass and chemicals industries.
We expect royalties generated from coal mining operations on our properties and our interest in the Ciner Wyoming soda
ash business to generate the substantial majority of our cash flow over the next years. However, over the past year, we have
been evaluating our existing portfolio of assets for opportunities to generate alternative sources of revenues without substantial
capital investment by us. For example, our surface and mineral acreage owned across the United States may contain geologic
formations that are suitable for the long-term sequestration and storage of carbon. To the extent a viable carbon sequestration
project is developed on or near our property, we may be able to lease that property as storage in exchange for rent payments.
We are also exploring opportunities to lease our surface acreage for renewable energy projects, such as solar arrays and wind
farms. In addition, we are assessing our forest timber assets for carbon sequestration project potential whereby we would obtain
and sell carbon offset credits in exchange for agreements for long-term forest preservation. There can be no assurance, however,
that any of these potential projects will succeed or generate substantial cash flow to NRP.
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.
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Our financial results by segment for the year ended December 31, 2020 are as follows:
(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)
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$ 129,592 $ 10,728 $
— $ 140,320
$ (40,180) $ 10,543 $ (55,182) $ (84,819)
135,885
—
—
135,885
$ 95,705 $ 10,543 $ (55,182) $ 51,066
$ 104,982 $ 14,025 $ (14,293) $ 104,714
$ 124,737 $ 14,037 $ (51,206) $ 87,568
$
$
1,745 $
— $
— $
1,745
— $
— $ (87,788) $ (87,788)
$ 127,482 $ 14,037 $ (51,206) $ 90,248
$ 125,859 $ 14,037 $ (51,206) $ 88,690
N/A
N/A
N/A $
(739)
(1) See "—Results of Operations" below for reconciliations to the most comparable GAAP financial measures.
Current Results/Market Commentary
Business Outlook and Quarterly Distributions
The global COVID-19 pandemic has had a significant negative impact on demand for steel, electricity and glass, which
translates to lower demand for the coal and soda ash that our properties produce. While demand for metallurgical and thermal
coals and soda ash began to rebound during the second half of 2020, prices remain below pre-pandemic levels, and the coal and
soda ash markets remain challenged. We are unable to predict the ultimate severity or duration of the COVID-19 pandemic or
its impact on our or Ciner Wyoming's business. We ended the year with $199.8 million of liquidity consisting of $99.8 million
of cash and cash equivalents and $100.0 million of borrowing capacity under our Opco Credit Facility and generated $88.7
million of free cash flow during the year ended December 31, 2020. As a result, we believe we have the financial flexibility to
navigate the effects of the pandemic on our business. We continue to employ remote work protocols and are conducting
business as usual despite the pandemic.
Despite our liquidity level at the end of the year, our consolidated leverage ratio has risen since early 2020 and was 4.6x at
December 31, 2020. The indenture governing our 2025 parent company notes restricts us from paying more than one-half of the
quarterly distribution on our preferred units in cash if our consolidated leverage ratio exceeds 3.75x. Accordingly, the Board of
Directors of our general partner has declared a distribution on our preferred units to be paid one-half in kind through the
issuance of additional preferred units (“PIK units”) for the past two quarters. To the extent our leverage ratio continues to
exceed 3.75x, which we expect for the foreseeable future, we will be required to continue to pay one-half of the required
preferred distributions in kind and will be unable to redeem any PIK units until our consolidated leverage ratio falls below
3.75x. Distributions on the outstanding PIK units will accrue and accumulate at 12% per year until such PIK units are
redeemed. In addition, pursuant to the terms of our partnership agreement, to the extent we have any PIK units outstanding after
January 1, 2022, we will be prohibited from paying any common unit distributions until the PIK units are redeemed in full.
Future distributions on NRP's common and preferred units will be determined on a quarterly basis by the Board of
Directors. The Board of Directors considers numerous factors each quarter in determining cash distributions, including
profitability, cash flow, debt service obligations, covenants in our debt and partnership agreements, market conditions and
outlook, estimated unitholder income tax liability and the level of cash reserves that the Board determines is necessary for
future operating and capital needs.
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Coal Royalty and Other Business Segment
Demand for steel and electricity began to rebound in the third quarter and the outlook for our coal businesses has
improved, though sales volumes and prices for coal sold from our properties in the fourth quarter remained below pre-pandemic
levels. We expect coal markets to remain volatile during 2021, in part as a result of ongoing uncertainties with the COVID-19
pandemic.
Our lessees sold 16.8 million tons of coal from our properties in 2020 and we derived approximately 70% of our coal
royalty revenues and approximately 60% of our coal royalty sales volumes from metallurgical coal during the same period.
Revenues and other income in 2020 were lower by $87.3 million as compared to the prior year. This decrease is primarily a
result of a weakened market for metallurgical coal as compared to the prior year due to a decline in global steel demand. As a
result, both sales volumes and prices for metallurgical coal sold were lower in 2020 compared to the prior year. Prices for
metallurgical coal have rebounded from the lows seen in the second quarter, but are not currently above pre-pandemic levels.
In addition, weaker domestic and export thermal coal markets compared to the prior year period resulted in lower
revenues from our thermal coal properties. Domestic and export thermal coal markets remained challenged by lower utility
demand, continued low natural gas prices and the secular shift to renewable energy. Our thermal coal business results are
largely dependent on our various lease agreements with Foresight. In June 2020, we entered into lease amendments with
Foresight pursuant to which Foresight agreed to pay us fixed cash payments of $48.75 million in 2020 and $42.0 million in
2021 to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee
agreements between us and Foresight for calendar years 2020 and 2021. These amendments provide us cash flow certainty for
our thermal coal business through 2021. During 2020 we received all of the $48.75 million due to us from Foresight.
Soda Ash Business Segment
Ciner Wyoming has been negatively impacted by the COVID-19 pandemic as lower demand for glass in the global auto,
beverage container, and construction industries reduced demand for soda ash. Revenues and other income in 2020 were lower
by $36.4 million compared to the prior year primarily due to a combination of lower pricing and volumes sold. However,
demand for glass began to rebound in the third quarter and the outlook for our soda ash business has improved. While Ciner
Wyoming's business has yet to recover to pre-COVID levels, overall sales volumes increased and overall production volumes
increased over second quarter 2020 lows, though global prices remain depressed. While we believe our facility is competitively
positioned as one of the lowest cost producers of soda ash in the world, we expect the market to remain volatile as a result of
ongoing uncertainties with the COVID-19 pandemic.
In order to have financial flexibility during the COVID-19 pandemic, Ciner Wyoming suspended quarterly distributions in
the third quarter of 2020. Ciner Wyoming will continue to evaluate, on a quarterly basis, whether to reinstate the distribution.
Ciner Wyoming’s ability to pay future quarterly distributions will be dependent in part on its cash reserves, liquidity, total debt
levels and anticipated capital expenditures. When considering the significant investment required by Ciner Wyoming’s
previously announced expansion project and the infrastructure improvements designed to increase overall efficiency, combined
with the COVID-19 pandemic’s negative impact on Ciner Wyoming’s financial results, Ciner Wyoming has reprioritized the
timing of the significant capital expenditure items in order to increase financial and liquidity flexibility until it has more clarity
and visibility into the ongoing impact of the COVID-19 pandemic on its business.
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Results of Operations
Years Ended December 31, 2020 and 2019 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,
2020
2019
Decrease
$
$
129,592 $
216,846 $
10,728
47,089
(87,254)
(36,361)
140,320 $
263,935 $
(123,615)
Percentage
Change
(40) %
(77) %
(47) %
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:
(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 (1)
Total coal royalty revenues
Other revenues
Production lease minimum revenues (1)
Minimum lease straight-line revenues (1)
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 asset sales and disposals
Total Coal Royalty and Other segment revenues and other income
For the Year Ended December 31,
2020
2019
Increase
(Decrease)
Percentage
Change
647
10,111
889
11,647
3,381
1,738
16,766
3,460
13,377
1,670
18,507
2,201
3,036
23,744
2.36 $
4.17
4.75
2.36
3.50
3.70
1.96 $
5.53
6.69
4.66
2.90
4.67
1,526 $
42,207
4,221
47,954
7,973
6,086
62,013
(10,145)
51,868 $
21,749 $
16,796
5,786
7,025
4,977
3,450
1,717
5,816
982
68,298 $
120,166 $
8,845
581
129,592 $
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 $
(2,813)
(3,266)
(781)
(6,860)
1,180
(1,298)
(6,978)
0.40
(1.36)
(1.94)
(2.30)
0.60
(0.97)
(5,249)
(31,753)
(6,948)
(43,950)
(2,282)
(2,723)
(48,955)
(8,789)
(57,744)
(2,319)
1,886
(501)
1,145
(8,519)
(4,541)
(2,548)
2,785
(547)
(13,159)
(70,903)
(10,434)
(5,917)
(87,254)
$
$
$
$
$
$
$
(81) %
(24) %
(47) %
(37) %
54 %
(43) %
(29) %
20 %
(25) %
(29) %
(49) %
21 %
(21) %
(77) %
(43) %
(62) %
(48) %
(22) %
(31) %
(44) %
(648) %
(53) %
(10) %
13 %
(8) %
19 %
(63) %
(57) %
(60) %
92 %
(36) %
(16) %
(37) %
(54) %
(91) %
(40) %
(1)
Effective January 1, 2020, certain revenues previously classified as coal royalty revenues are classified as production lease
minimum revenues or minimum lease straight-line revenues due to contract modifications with Foresight Energy
Resources LLC ("Foresight") that fixed consideration paid to us over a two-year period.
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Coal Royalty Revenues
Total coal royalty revenues decreased $57.7 million from 2019 to 2020 driven by weakened coal markets that resulted in
lower coal sales volumes and pricing. The discussion of these decreases by region is as follows:
•
•
•
•
•
Appalachia: Sales volumes decreased 37% and coal royalty revenues decreased $44.0 million primarily due to weakened
coal demand compounded by the COVID-19 pandemic.
Illinois Basin: Sales volumes increased 54% due to increased activity at the Hillsboro and Williamson mines, while coal
royalty revenues decreased $2.3 million primarily due to the idling of our Macoupin property. Additionally, during the
year ended December 31, 2020, certain revenues previously classified as coal royalty revenues are classified as production
lease minimum revenues or minimum lease straight-line revenues due to contract modifications with Foresight that fixed
consideration paid to us over a two-year period.
Northern Powder River Basin: Sales volumes decreased 43% and coal royalty revenues decreased $2.7 million
primarily due to our lessee mining off of our property in accordance with its mine plan in 2020, partially offset by a 21%
increase in sales prices year-over-year.
Other Revenues
Other revenues decreased $13.2 million from 2019 to 2020 primarily due to the following:
A $8.5 million decrease in coal overriding royalty revenues primarily as a result of production at the Williamson mine
moving off of non-NRP owned coal (on which we receive overriding royalties) and back onto NRP-owned coal reserves.
As a result, this decrease in coal overriding royalty revenues was offset by an increase in coal royalty revenues; and
A $4.5 million decrease in lease amendment revenues year-over-year.
Transportation and Processing Services Revenues
Transportation and processing services revenues decreased $10.4 million primarily due to the temporary cessation of
production at the Macoupin mine where we own loadout and other transportation assets in addition to decreased production of
non-NRP-owned coal at the Williamson mine where we also own loadout and other transportation assets.
Gain on Asset Sales and Disposals
Gain on asset sales and disposals decreased $5.9 million primarily due to the disposal of certain mineral rights assets
during the third quarter of 2019.
Soda Ash
Revenues and other income related to our Soda Ash segment decreased $36.4 million primarily due to a combination of
lower pricing and volumes sold. Ciner Wyoming was negatively impacted by the COVID-19 pandemic as lower demand for
glass in the global auto, beverage container, and construction industries reduced demand for soda ash.
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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
For the Year Ended
December 31,
2020
2019
Decrease
Percentage
Change
$
24,795 $
9,198
32,738 $
14,932
14,293
135,885
16,730
148,214
(7,943)
(5,734)
(2,437)
(12,329)
(24) %
(38) %
(15) %
(8) %
(13) %
Total operating expenses
$
184,171 $
212,614 $
(28,443)
Other expenses, net
Interest expense, net
Loss on extinguishment of debt
Total other expenses, net
$
$
40,968 $
47,453 $
(6,485)
—
29,282
(29,282)
40,968 $
76,735 $
(35,767)
(14) %
(100) %
(47) %
Total operating expenses decreased by $28.4 million primarily due to the following:
Asset impairments decreased $12.3 million from 2019 to 2020. Asset impairments in the year ended December 31, 2020
were primarily due to weakened coal markets that resulted in termination of certain coal leases, changes to lessee mine
plans resulting in permanent moves off certain of our coal properties and decreased oil and gas drilling activity which
negatively impacted the outlook for NRP's frac sand properties. 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.
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 decreased $7.9
million primarily due to a decrease in bad debt expense in addition to lower costs related to an overriding royalty
agreement with Western Pocahontas Properties Limited Partnership ("WPPLP"). The coal royalty expense NRP pays to
WPPLP is fully offset by the coal royalty revenue NRP receives from this property.
Depreciation, depletion and amortization expense decreased $5.7 million due to lower coal sales volumes at certain
properties.
General and administrative expenses decreased $2.4 million primarily due to decreased legal expenses year-over-year.
Total other expenses, net decreased $35.8 million primarily due to the following:
Loss on extinguishment of debt of $29.3 million in 2019 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 $6.5 million primarily due to lower debt balances in 2020 as a result of debt repayments
made over the past twelve months.
•
•
•
•
•
•
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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, 2020
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate and
Financing
Total
Net income (loss) from continuing operations
$
(40,180) $
10,543 $
(55,182) $
(84,819)
Less: equity earnings from unconsolidated investment
Add: total distributions from unconsolidated investment
Add: interest expense, net
Add: depreciation, depletion and amortization
Add: asset impairments
—
—
79
9,198
135,885
(10,728)
14,210
—
—
—
—
—
40,889
—
—
(10,728)
14,210
40,968
9,198
135,885
Adjusted EBITDA
December 31, 2019
$
104,982 $
14,025 $
(14,293) $
104,714
Net income (loss) from continuing operations
$
21,211 $
46,840 $
(93,465) $
(25,414)
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
Adjusted EBITDA
—
—
—
—
14,932
148,214
(47,089)
31,850
—
—
—
—
—
—
47,453
29,282
—
—
(47,089)
31,850
47,453
29,282
14,932
148,214
$
184,357 $
31,601 $
(16,730) $
199,228
•
•
Adjusted EBITDA decreased $94.5 million primarily due to the following:
Coal Royalty and Other Segment
◦
Adjusted EBITDA decreased $79.4 million primarily as a result of weaker coal markets in the year ended
December 31, 2020.
Soda Ash Segment
◦
Adjusted EBITDA decreased $17.6 million as a result of lower cash distributions received from Ciner Wyoming
during the year ended December 31, 2020.
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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, 2020
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
$
124,737 $
14,037 $
(51,206) $
87,568
1,745
—
—
—
—
1,745
(87,788)
(87,788)
December 31, 2019
Cash flow provided by (used in) continuing operations
Operating activities
Investing activities
Financing activities
$
178,863 $
31,601 $
(73,145) $
137,319
8,221
—
—
—
—
8,221
(253,305)
(253,305)
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, 2020
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
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate and
Financing
Total
$
124,737 $
14,037 $
(51,206) $
87,568
623
—
2,122
—
—
—
—
—
—
623
(65)
2,122
Distributable cash flow
$
127,482 $
14,037 $
(51,206) $
90,248
Less: proceeds from asset sales and disposals
Less: proceeds from sale of discontinued operations
Less: acquisition costs
Free cash flow
Less: mandatory Opco debt repayments
Less: preferred unit distributions
Less: common unit distributions
Cash flow cushion
(623)
—
(1,000)
—
—
—
—
—
—
(623)
65
(1,000)
$
125,859 $
14,037 $
(51,206) $
88,690
(46,176)
(26,363)
(16,890)
$
(739)
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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
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate and
Financing
Total
$
178,863 $
31,601 $
(73,145) $
137,319
6,500
—
1,743
—
—
—
—
—
—
6,500
(629)
1,743
Distributable cash flow
$
187,106 $
31,601 $
(73,145) $
144,933
Less: proceeds from asset sales and disposals
Less: proceeds from sale of discontinued operations
Less: expansion capital expenditures
(6,500)
—
(22)
—
—
—
—
—
—
(6,500)
629
(22)
Free cash flow
$
180,584 $
31,601 $
(73,145) $
139,040
Less: mandatory Opco debt repayments
Less: preferred unit distributions
Less: common unit distributions
Cash flow cushion
(68,128)
(30,000)
(33,150)
$
7,762
DCF and FCF decreased $54.7 million and $50.4 million, respectively, primarily due to the following:
•
Coal Royalty and Other Segment
◦
DCF and FCF decreased $59.6 million and $54.7 million, respectively, primarily as a result of the weakened coal
markets in the year ended December 31, 2020. DCF was also impacted by a $5.9 million decrease in proceeds
from asset sales and disposals compared to the year ended December 31, 2019.
•
•
Soda Ash Segment
◦
DCF and FCF decreased $17.6 million as a result of lower cash distributions received from Ciner Wyoming
during the year ended December 31, 2020.
Corporate and Financing Segment
◦
DCF and FCF increased $21.9 million primarily due to lower cash paid for interest as a result of less debt
outstanding in 2020.
Cash flow cushion decreased $8.5 million as a result of the decrease in FCF discussed above, partially offset by a
decrease in mandatory Opco debt repayments and lower preferred unit and common unit distributions made during the year
ended December 31, 2020.
For discussion of our Results of Operations comparing 2019 to 2018, refer to our 2019 Annual Report on Form 10-K
filed February 27, 2020 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, 2020, we had total liquidity of $199.8 million, consisting of $99.8 million of cash and cash
equivalents and $100.0 million in borrowing capacity under our Opco Credit Facility. We have significant debt service
obligations, including approximately $40 million of principal repayments on Opco’s senior notes in 2021. We believe our
liquidity position provides us with the flexibility to continue paying down debt and manage our business through the current
market environment.
Cash Flows
Years Ended December 31, 2020 and 2019 Compared
Cash flows provided by operating activities decreased $48.0 million, from $137.3 million in the year ended December 31,
2019 to $89.3 million in the year ended December 31, 2020 primarily related to lower operating cash flow as a result of the
weakened coal markets in addition to lower cash distributions received from Ciner Wyoming in 2020, partially offset by less
cash paid for interest in 2020 due to less debt outstanding.
Cash flows provided by investing activities decreased $5.9 million, from $7.6 million in the year ended December 31,
2019 to $1.7 million in the year ended December 31, 2020 primarily due to a $5.9 million decrease in proceeds from asset sales
and disposals year-over-year.
Cash flows used in financing activities decreased $163.2 million, from $252.7 million in the year ended December 31,
2019 to $89.4 million in the year ended December 31, 2020 primarily due to the following:
•
•
•
•
•
$345.6 million used for the redemption of our 2022 Senior Notes in the second quarter of 2019;
The $49.3 million prepayment of our Opco Senior Notes in the first quarter of 2019 made using proceeds from the sale of
our construction aggregates business;
$26.4 million in debt issuance costs and other primarily in 2019 primarily related to the 2019 debt refinancings;
$16.3 million in lower common unit distributions in the year ended December 31, 2020 as a result of the special common
unit distribution paid in 2019 to cover common unitholders' tax liability resulting from the sale of NRP's construction
aggregates business in December 2018, and the suspension of the distribution on NRP's common units with respect to the
first quarter of 2020.
$3.6 million in lower preferred unit distributions in the year ended December 31, 2020 as a result of paying half of the
distribution in kind through the issuance of additional preferred units during the fourth quarter of 2020.
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.
For discussion of our Cash Flows comparing 2019 to 2018, refer to our 2019 Annual Report on Form 10-K filed February
27, 2020 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Capital Resources and Obligations
Debt, Net
We had the following debt outstanding as of December 31, 2020 and 2019:
(In thousands)
Current portion of long-term debt, net
Long-term debt, net
Total debt, net
46
December 31,
2020
2019
$
$
39,055 $
432,444
471,499 $
45,776
470,422
516,198
Table of Contents
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 11. Debt, Net" in this Annual Report on
Form 10-K.
Debt Obligations
The following table reflects our long-term, non-cancelable debt obligations as of December 31, 2020:
Debt Obligations (In thousands)
NRP:
Debt principal payments (1)
Debt interest payments (1)
Opco:
Debt principal payments (including
current maturities) (2)
Debt interest payments (3)
Total
Total
2021
2022
2023
2024
2025
Thereafter
Payments Due by Period
$ 300,000 $
— $
— $
— $
— $ 300,000 $
123,188
27,375
27,375
27,375
27,375
13,688
—
—
177,880
39,396
39,396
39,396
31,028
14,332
14,332
27,418
9,868
7,631
5,020
2,724
1,450
725
$ 628,486 $ 76,639 $ 74,402 $ 71,791 $ 61,127 $ 329,470 $ 15,057
(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, 2020 we did not have any
borrowings outstanding under the Opco Credit Facility and had $100 million in available borrowing capacity.
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.
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, 2020, 2019 and 2018.
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 13.
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.
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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 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.
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.
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).
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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 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
49
Table of Contents
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, including intangible 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As a smaller reporting company for the year ended December 31, 2020, we are not required to include this disclosure in our
2020 Form 10-K.
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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, 2020 and 2019
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Partners’ Capital for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
Notes to Consolidated Financial Statements
Page
52
54
56
57
58
59
61
51
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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, 2020 and 2019, 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, 2020, 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, 2020 and
2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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 $263 million as of December 31, 2020 and 2019, respectively, and the Partnership’s equity in the net
income of Ciner Wyoming is stated at $11 million in 2020, $47 million in 2019 and $48 million in 2018. 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, 2020, 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 March 15, 2021 expressed an unqualified opinion thereon.
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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The
communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken
as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit
matter or on the account or disclosure to which it relates.
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Table of Contents
Impairment Assessment of Mineral Rights and Intangible Assets
Description of the
Matter
How We Addressed the
Matter in Our Audit
At December 31, 2020, the Partnership's Mineral Rights, net and Intangible assets, net totaled a
combined $478 million. During 2020, the Partnership recorded $136 million of mineral rights
impairment expense. As more fully described in Note 2 to the consolidated financial statements, the
Partnership evaluates 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 ("triggering
events"). If deemed to be impaired, impairment is measured based on the estimated fair value,
usually determined using the present value of projected future cash flows, compared to the asset’s
book value.
Auditing the Partnership's impairment assessment involved our subjective judgment because, in
determining the fair value of assets, management uses estimates that include, among others,
assumptions about forecasted coal and aggregates prices and future production using mineral reserve
or other relevant information reported by the third-party mine operators. Significant uncertainty
exists with these assumptions, given the long term nature of the forecast period and estimation of
future market prices.
We obtained an understanding, evaluated the design and tested the operating effectiveness of
controls over the Partnership’s impairment review process, including the processes to determine the
fair value of the asset groups. This included evaluating controls over the Partnership's budgetary and
forecasting process used to develop the estimated future cash flows. We also tested controls over
management's review of the data used in the impairment analysis and review of the significant
assumptions such as forecasted production and pricing.
To test the estimated fair value of the assets, we performed audit procedures that included, among
others, assessing methodologies and testing significant assumptions. We compared forecasted coal
and aggregates prices to available market information and compared royalty rate inputs to customer
contracts. We tested production estimates through corroborating reserve information and mining
plans to available third-party mine operators or publicly available information. We considered
possible contradictory information by comparing to historical results and projections utilized in other
management analyses for going concern and estimated credit losses.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2002.
Houston, Texas
March 15, 2021
53
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To 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, 2020 and
2019, 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, 2020, and the related notes that are 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and
we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the
accounts or disclosures to which it relates.
Agreements and Transactions with Affiliates – Refer to Notes 1, 2, 8, 12, and 13 to the financial statements
54
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Critical Audit Matter Description
The Company is a subsidiary in a global group structure and agreements directly between the Company and other affiliates, or
indirectly between affiliates that the Company does not control, can have a significant impact on recorded amounts or
disclosures in the Company's financial statements, including any commitments and contingencies between the Company and
affiliates or, potentially, third parties. Performing audit procedures to evaluate the Company’s identification of upstream
affiliate relationships, transactions, and commitments and contingencies outside of the U.S. and the impact of such matters on
the financial statements represents a critical audit matter because of the increased auditor judgment necessary to perform audit
procedures related to these matters and evaluate the results of those procedures.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Company’s identification of upstream affiliate relationships, transactions, and commitments
and contingencies outside of the U.S. and the impact of such matters on the financial statements included the following, among
others:
• We tested the effectiveness of controls over the Company’s affiliate process, including controls over the identification of
the Company’s affiliate relationships, transactions, and commitments and contingencies outside of the U.S.
• We read publicly available financial filings and news sources related to the Company and its affiliates outside of the U.S.
and listened to the parent company (Ciner Resources LP) quarterly investor relations calls for information related to
potential new affiliates and transactions between the Company and affiliates.
• We inspected director and executive officer questionnaires from the parent company directors and officers to identify any
affiliate matters.
• We searched the general ledger for potential transactions with affiliates.
• We read significant new or amended agreements and contracts of the Company to identify new affiliate relationships,
transactions, or commitments and contingencies, and evaluated management’s analyses regarding the accounting and
disclosure of such arrangements.
• We inquired of executive officers, key members of management, and the Board of Managers regarding affiliate
relationships, transactions and commitments and contingencies.
• We confirmed with the ultimate parent company that the affiliate relationships, transactions, and commitments and
contingencies identified and disclosed by the Company were complete.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 15, 2021
We have served as the Company’s auditor since 2008.
55
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data)
Current assets
ASSETS
Cash and cash equivalents
Accounts receivable, net
Other current assets, net
Current assets of discontinued operations
Total current assets
Land
Mineral rights, net
Intangible assets, net
Equity in unconsolidated investment
Long-term contract receivable, net
Other long-term assets, net
Total assets
Current liabilities
LIABILITIES AND CAPITAL
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 15)
Class A Convertible Preferred Units (253,750 and 250,000 units issued and outstanding at
December 31, 2020 and 2019, respectively, at $1,000 par value per unit; liquidation
preference of $1,700 per unit and $1,500 per unit at December 31, 2020 and 2019,
respectively)
Partners’ capital
Common unitholders’ interest (12,261,199 units issued and outstanding at December 31,
2020 and 2019)
General partner’s interest
Warrant holders’ interest
Accumulated other comprehensive income (loss)
Total partners’ capital
Non-controlling interest
Total capital
Total liabilities and capital
December 31,
2020
2019
99,790 $
12,322
5,080
—
117,192 $
24,008
460,373
17,459
262,514
33,264
7,067
921,877 $
1,385 $
7,733
1,714
11,485
39,055
—
61,372 $
50,069
432,444
5,131
549,016 $
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
$
$
$
$
$
$
$
168,337 $
164,587
$
$
$
$
136,927 $
459
66,816
322
204,524 $
—
204,524 $
921,877 $
271,471
3,270
66,816
(2,594)
338,963
(2,935)
336,028
1,085,907
The accompanying notes are an integral part of these consolidated financial statements.
56
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 (loss) from operations
Other expenses, net
Interest expense, net
Loss on extinguishment of debt
Total other expenses, net
Net income (loss) from continuing operations
Income from discontinued operations (see Note 20)
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 the
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 6)
Basic
Diluted
Net income (loss) per common unit (see Note 6)
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 Year Ended December 31,
2020
2019
2018
120,166 $
8,845
10,728
—
581
140,320 $
24,795 $
9,198
14,293
135,885
184,171 $
191,069 $
19,279
47,089
—
6,498
263,935 $
32,738 $
14,932
16,730
148,214
212,614 $
178,878
23,887
48,306
25,000
2,441
278,512
29,509
21,689
16,496
18,280
85,974
(43,851) $
51,321 $
192,538
(40,968) $
—
(40,968) $
(84,819) $
—
(84,819) $
—
(84,819) $
(30,225)
(47,453) $
(29,282)
(76,735) $
(25,414) $
956
(24,458) $
—
(24,458) $
(30,000)
(70,178)
—
(70,178)
122,360
17,687
140,047
(510)
139,537
(30,000)
(115,044) $
(54,458) $
109,537
(112,743) $
(2,301)
(53,369) $
(1,089)
107,346
2,191
(9.20) $
(9.20)
(4.43) $
(4.43)
(9.20) $
(9.20)
(4.35) $
(4.35)
7.35
5.90
8.77
6.76
(84,819) $
(24,458) $
140,047
2,916
(81,903) $
—
(81,903) $
868
(23,590) $
—
(23,590) $
(149)
139,898
(510)
139,388
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
57
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Balance at December 31, 2017
Cumulative effect of adoption of
accounting standard
Net income (1)
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
Common Unitholders
Units
Amounts
General
Partner
Warrant
Holders
Accumulated
Other
Comprehensive
Income (Loss)
Partners'
Capital
Excluding
Non-
Controlling
Interest
Non-
Controlling
Interest
Total
Capital
12,232 $ 199,851 $ 1,857 $ 66,816 $
(3,313) $ 265,211 $
(3,394) $ 261,817
—
—
69,057
136,746
1,409
2,791
—
(22,036)
(450)
—
17
—
—
(29,660)
(605)
546
560
49
—
—
12
—
—
—
—
—
—
—
—
—
—
—
—
—
70,466
—
70,466
139,537
510
140,047
(22,486)
—
(22,486)
(30,265)
546
560
—
—
—
(30,265)
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 (1)
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)
—
12
—
—
(29,400)
(600)
486
1,804
—
—
(76)
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
Cumulative effect of adoption of
accounting standard (See Note
18)
Net loss (2)
Distributions to common
unitholders and general partner
Distributions to preferred
unitholders
Acquisition of non-controlling
interest in BRP
Issuance of unit-based awards
Unit-based awards amortization
and vesting
Comprehensive income from
unconsolidated investment and
other
—
(3,833)
(78)
—
(83,123)
(1,696)
—
(16,552)
(338)
—
(29,511)
(602)
—
—
—
—
(4,747)
—
3,222
—
(97)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(3,911)
(84,819)
—
—
(3,911)
(84,819)
(16,890)
—
(16,890)
(30,113)
—
(30,113)
(4,844)
2,935
(1,909)
—
3,222
—
—
—
3,222
2,916
2,916
—
2,916
Balance at December 31, 2020
12,261 $ 136,927 $
459 $ 66,816 $
322 $ 204,524 $
— $ 204,524
(1) Net income (loss) includes $30.0 million of income 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.
(2) Net loss includes $30.2 million of income attributable to preferred unitholders that accumulated during the period, of which
$29.6 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.
58
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(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:
For the Year Ended December 31,
2020
2019
2018
$
(84,819) $
(24,458) $
140,047
Depreciation, depletion and amortization
Distributions from unconsolidated investment
Equity earnings from unconsolidated investment
Gain on asset sales and disposals
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 receivable
Acquisition of non-controlling interest in BRP
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
Cash flows from financing activities
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
$
$
$
$
$
$
$
$
59
9,198
14,210
(10,728)
(581)
—
—
135,885
4,001
3,570
1,323
12,853
207
(2,205)
(602)
9,733
(4,477)
87,568 $
1,706
89,274 $
— $
623
2,122
(1,000)
—
1,745 $
(65)
1,680 $
— $
(46,176)
—
(16,890)
(26,363)
1,641
—
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)
8,221 $
(629)
7,592 $
300,000 $
(463,082)
—
(33,150)
(30,000)
(637)
(26,436)
(87,788) $
(253,305) $
(1,641)
(89,429) $
637
(252,668) $
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
—
—
7,607
183,021
190,628
35,000
(175,706)
(8,844)
(22,486)
(30,265)
195,690
(228)
(6,839)
(196,509)
(203,348)
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents of continuing operations at beginning of period
Cash and cash equivalents of discontinued operations at beginning of period
Cash and cash equivalents at beginning of period
Cash and cash equivalents of continuing operations at end of period
Less: cash and cash equivalents of discontinued operations at end of period
Cash and cash equivalents at end of period
Supplemental cash flow information:
Cash paid during the period for interest
Non-cash investing and financing activities:
Plant, equipment, mineral rights and other funded with accounts payable or
accrued liabilities
Preferred unit distributions paid-in-kind
For the Year Ended December 31,
2020
2019
2018
1,525 $
(107,765) $
176,203
98,265 $
206,030 $
—
—
98,265 $
206,030 $
26,980
2,847
29,827
99,790 $
98,265 $
206,030
—
—
—
99,790 $
98,265 $
206,030
39,830 $
58,597 $
64,991
970 $
3,750
— $
—
—
—
$
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
60
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 7.
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. 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.
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 12. Fair Value Measurements for further details.
•
•
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.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
•
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 and Cash Equivalents
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be
cash equivalents
Allowance for Doubtful Accounts
The Partnership records an allowance for doubtful accounts for its accounts receivable and notes receivable comprised of
estimated credit risk and non-credit risk (e.g., legal disputes) losses. Receivables are written off when collection efforts are
exhausted and future recovery is doubtful. Beginning January 1, 2020 upon adoption of ASU No. 2016-13, the Partnership
includes an allowance for current expected credit losses ("CECL") on its financial assets based on the loss-rate method. NRP
assesses the likelihood of collection of its receivables utilizing historical loss rates, current market conditions that include the
estimated impact of the global COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts
and facts or circumstances of individual customers and properties. See Note 18. Credit Losses for more information. The total
allowance related to accounts receivables included in accounts receivables, net on the Partnership's Consolidated Balance
Sheets was $1.7 million and $0.4 million at December 31, 2020 and 2019, respectively. The total allowance related to short-
term notes receivables included in other current assets, net on the Partnership's Consolidated Balance Sheets was $0.6 million
and $1.2 million at December 31, 2020 and 2019, respectively. The total allowance related to the Partnership's long-term
financing receivable included in long-term contract receivable, net on the Consolidated Balance Sheets was $1.6 million at
December 31, 2020. The Partnership recorded bad debt expense of $4.0 million, $7.5 million and $(0.1) million included in
operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) for the years ended
December 31, 2020, 2019 and 2018, 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, including intangible 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.
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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, 2020 were $3.7 million
of accrued employee costs and $4.0 million of other accrued liabilities, which primarily includes property taxes. These amounts
were $3.7 million and $5.0 million of accrued employee costs and other accrued liabilities, respectively, at December 31, 2019.
Other accrued liabilities at December 31, 2019 primarily included property 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.
The Partnership has defined its coal and aggregates royalty lease performance obligation as providing the lessee the right
to mine and sell its coal or aggregates over the lease term. NRP then evaluated the likelihood that consideration it 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.
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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.
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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).
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 16. 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 long-term 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
Credit Losses
On January 1, 2020, the Partnership adopted ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326), and
all the related amendments ("the new credit loss standard"). The Partnership recognized a $3.9 million cumulative effect of
adoption in the opening balance of partners' capital on January 1, 2020 as a result of the adoption of the new credit loss
standard. 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. See Note 18. Credit Losses for
more information.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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
For the Year Ended December 31,
2020
2019
2018
$
51,868 $
109,612 $
129,341
21,749
16,796
5,786
7,025
4,977
3,450
1,717
5,816
982
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
Transportation and processing services revenues (1)
Total coal royalty and other segment revenues
$
$
120,166 $
191,069 $
8,845
19,279
129,011 $
210,348 $
(1) Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $5.0
million, $9.6 million and $13.2 million for the year ended December 31, 2020, 2019 and 2018, respectively. The
remaining transportation and processing services revenues of $3.8 million, $9.7 million and $10.7 million for the year
ended December 31, 2020, 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 17. Financing Transaction for more information.
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
Other current assets, net (1)
Other long-term assets, net (2)
Contract liabilities
Current portion of deferred revenue
Deferred revenue
December 31,
2020
2019
$
$
10,193 $
3,307
525
11,485 $
50,069
27,915
90
—
4,608
47,213
(1) Other current assets, net includes short-term notes receivables from contracts with customers.
(2) Other long-term assets, net includes long-term lease amendment fee receivables from contracts with customers.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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)
$
$
$
For the Year Ended December 31,
2020
2019
2018
51,821 $
52,553 $
—
51,821 $
41,557
(31,824)
61,554 $
—
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 as of December 31, 2020 (in thousands):
Lease Term (1)
0 - 5 years
5 - 10 years
10+ years
Total
Weighted Average
Remaining Years
Annual Minimum
Payments (2)
4.4
5.4
13.7
9.6
$
$
13,349
8,022
30,130
51,501
(1) Lease term does not include renewal periods.
(2) Annual minimum payments do not include $19.3 million of the $40.0 million of annual fixed consideration owed to NRP
in 2021 resulting from contract modifications entered into during the second quarter of 2020. Additionally, $5.0 million of
this remaining $19.3 million relates to a coal infrastructure lease that is accounted for as a financing transaction. See Note
17. Financing Transaction for additional information.
4. 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.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
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.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
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, 2017
Redemption of PIK units
Balance at December 31, 2018 and 2019
Distribution paid-in-kind
Balance at December 31, 2020
Units Outstanding
Financial
Position
258,844 $
173,431
(8,844)
(8,844)
250,000 $
164,587
3,750
3,750
$
253,750 $
168,337
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 12. Fair Value Measurements for further information regarding valuation of these
embedded derivatives.
5. 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
$30.2 million during the year ended December 31, 2020 and $30.0 million during the years ended December 31, 2019 and 2018
as a result of accumulated preferred unit distributions earned during the period. In May 2020, the Partnership paid in kind one-
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
half of the preferred unit distribution related to the three months ended March 31, 2020. In June 2020, the Partnership redeemed
all of the outstanding preferred units paid in kind. Additionally, in November 2020, the Partnership paid in kind one-half of the
preferred unit distribution related to the three months ended September 30, 2020. During the three months ended March 31,
2018, the Partnership redeemed all of the outstanding PIK units related to the year ended December 31, 2017, which resulted in
an $8.8 million cash payment during the year ended December 31, 2018. This $8.8 million cash payment is not included in the
table below.
The following table shows the cash distributions declared and paid to common and preferred unitholders during the years
ended December 31, 2020, 2019 and 2018, respectively:
Date Paid
Period Covered by Distribution
2020
Common Units
Preferred Units
Distribution
per Unit
Total
Distribution (1)
(In thousands)
Distribution
per Unit
Total
Distribution
(In thousands)
February 2020
October 1 - December 31, 2019 $
0.45 $
5,630 $
30.00 $
May 2020
June 2020 (2)
August 2020
January 1 - March 31, 2020
January 1 - March 31, 2020
April 1 - June 30, 2020
November 2020
July 1 - September 30, 2020
—
—
0.45
0.45
—
—
5,630
5,630
15.00
15.45
30.00
15.00
2019
February 2019
October 1 - December 31, 2018 $
0.45 $
5,625 $
30.00 $
May 2019
May 2019 (3)
August 2019
January 1 - March 31, 2019
Special Distribution
April 1 - June 30, 2019
November 2019
July 1 - September 30, 2019
0.45
0.85
0.45
0.45
5,630
10,635
5,630
5,630
30.00
—
30.00
30.00
2018
February 2018
May 2018
August 2018
October 1 - December 31, 2017 $
0.45 $
5,617 $
30.00 $
November 2018
July 1 - September 30, 2018
January 1 - March 31, 2018
April 1 - June 30, 2018
0.45
0.45
0.45
5,623
5,623
5,623
30.00
30.00
30.00
7,500
3,750
3,863
7,500
3,750
7,500
7,500
—
7,500
7,500
7,765
7,500
7,500
7,500
(1) Total common unit distribution includes the amount paid to NRP's general partner in accordance with the general partner's
2% general partner interest.
(2) Redemption of preferred units paid in kind plus accrued interest.
(3) Special distribution was made to cover the common unitholders' tax liability resulting from the sale of NRP's construction
aggregates business in December 2018.
6. 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
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
for purposes of the if-converted calculation. The calculation of diluted net loss per common unit for the years ended December
31, 2020 and 2019 do not include the assumed conversion of the preferred units because the impact would have been anti-
dilutive. The calculation of diluted net income per common unit for the year ended December 31, 2018 includes 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 years ended December 31, 2020 and 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 year ended December 31, 2018
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.
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 the 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
For the Year Ended December 31,
2020
2019
2018
$
(84,819) $
(25,414) $
122,360
—
—
(510)
(30,225)
(30,000)
(30,000)
$
(115,044) $
(55,414) $
91,850
2,301
1,108
(1,837)
$
(112,743) $
(54,306) $
90,013
$
$
$
— $
956 $
17,687
—
(19)
(354)
— $
937 $
17,333
(84,819) $
—
(24,458) $
—
140,047
(510)
(30,225)
(30,000)
(30,000)
Net income (loss) attributable to common unitholders and the general
partner
$
(115,044) $
(54,458) $
109,537
Add (less): net loss (income) attributable to the general partner
2,301
1,089
(2,191)
Net income (loss) attributable to common unitholders
$
(112,743) $
(53,369) $
107,346
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
12,261
12,260
12,244
$
$
$
(9.20) $
— $
(9.20) $
(4.43) $
0.08 $
(4.35) $
7.35
1.42
8.77
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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: income attributable to preferred unitholders
Diluted net income (loss) from continuing operations attributable to
common unitholders and the 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: income attributable to preferred unitholders
Diluted net income (loss) attributable to common unitholders and the
general partner
Add (less): diluted net loss (income) attributable to the general
partner
For the Year Ended December 31,
2020
2019
2018
12,261
12,260
—
—
—
—
—
—
12,244
7,479
511
—
12,261
12,260
20,234
$
(84,819) $
(25,414) $
122,360
—
—
(30,225)
(30,000)
(510)
—
$
(115,044) $
(55,414) $
121,850
2,301
1,108
(2,437)
$
(112,743) $
(54,306) $
119,413
$
$
— $
937 $
17,333
(84,819) $
(24,458) $
140,047
—
—
(30,225)
(30,000)
(510)
—
$
(115,044) $
(54,458) $
139,537
2,301
1,089
(2,791)
Diluted net income (loss) attributable to common unitholders
$
(112,743) $
(53,369) $
136,746
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
$
$
$
(9.20) $
— $
(9.20) $
(4.43) $
0.08 $
(4.35) $
5.90
0.86
6.76
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
7. 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 Wyoming mines trona and processes it into soda
ash that is sold both domestically and internationally into 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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NATURAL RESOURCE PARTNERS L.P.
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, 2020
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
As of December 31, 2020
Total assets of continuing operations
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
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$ 129,011 $ 10,728 $
581
24,610
9,198
—
135,885
79
(40,180)
—
185
—
—
—
—
10,543
— $ 139,739
581
—
24,795
—
9,198
—
14,293
14,293
135,885
—
40,968
40,889
(84,819)
(55,182)
$ 656,505 $ 262,514 $
2,858 $ 921,877
$ 210,348 $ 47,089 $
6,498
32,489
14,932
—
148,214
—
21,211
—
—
249
—
—
—
—
46,840
—
— $ 257,437
6,498
—
32,738
—
14,932
—
16,730
16,730
148,214
—
76,735
76,735
(25,414)
(93,465)
956
—
$ 817,768 $ 263,080 $
—
—
3,353 $ 1,084,201
1,706
—
$ 202,765 $ 48,306 $
25,000
2,441
29,509
21,689
—
18,280
—
160,728
—
—
—
—
—
—
—
—
48,306
—
— $ 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
—
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
8. 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,
2020
2019
2018
$
263,080 $
247,051 $
245,433
15,205
52,016
(4,477)
(4,927)
2,916
790
53,095
(4,789)
(138)
(14,210)
(31,850)
(46,550)
$
262,514 $
263,080 $
247,051
(1)
Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $1.7
million, $0.6 million and $0.5 million for the year ended December 31, 2020, 2019 and 2018, 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 $131.4 million and $135.8 million as of December 31, 2020 and 2019, 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 27 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, 2020, 2019, and 2018:
(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,
2020
2019
2018
$
392,231 $
522,843 $
486,759
54,838
31,030
131,712
106,155
104,053
108,357
December 31,
2020
2019
$
164,720 $
294,008
55,313
135,776
170,696
282,387
55,339
138,087
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9. Mineral Rights, Net
The Partnership’s mineral rights consist of the following:
December 31,
2020
2019
(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
$ 785,623 $ (346,773) $ 438,850 $ 981,352 $ (420,448) $ 560,904
9,039
12,354
13,154
(2,819)
(8,593)
6,220
3,761
(1,612)
11,542
41,486
12,395
13,156
(13,357)
28,129
(7,887)
4,508
(1,601)
11,555
Total mineral rights, net
$ 820,170 $ (359,797) $ 460,373 $ 1,048,389 $ (443,293) $ 605,096
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 $8.8 million, $12.1 million and $17.0 million for the
years ended December 31, 2020, 2019 and 2018, respectively.
Sales of Mineral Rights
During the year ended December 31, 2020, the Partnership recorded a gain of $0.6 million included in gain on asset sales
and disposals on the Consolidated Statements of Comprehensive Income (Loss) related to sales of multiple mineral reserves.
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 year ended December 31, 2018, the Partnership recorded a cumulative gain
of $2.4 million 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, 2020, 2019 and 2018, 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 properties (2)
Total
For the Year Ended December 31,
2020
2019
2018
$
114,302 $
21,583
125,806 $
103
$
135,885 $
125,909 $
5,259
13,021
18,280
(1) The Partnership recorded $114.3 million of impairment expense to impair certain assets during the year ended December
31, 2020 primarily related to weakened coal markets that resulted in termination of certain coal leases and changes to
lessee mine plans resulting in permanent moves off certain of our coal properties. 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. NRP compared the net
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 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 $21.6 million of aggregates royalty property impairments during the year ended December 31,
2020 primarily related to decreased oil and gas drilling activity which negatively impacted the outlook for NRP's frac sand
properties. 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%. 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 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.
While the Partnership's impairment evaluation as of December 31, 2020 incorporated an estimated impact of the global
COVID-19 pandemic, there is significant uncertainty as to the severity and duration of this disruption. If the impact is worse
than we currently estimate, an additional impairment charge may be recognized in future periods.
10. Intangible Assets, Net
The Partnership's intangible assets consist of above-market coal royalty and related transportation contracts with
subsidiaries of Foresight Energy Resources LLC ("Foresight") 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,
2020
2019
$
$
53,878 $
(36,419)
17,459 $
53,878
(36,191)
17,687
Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements
of Comprehensive Income (Loss) was $0.2 million, $2.5 million and $4.3 million for the years ended December 31, 2020, 2019
and 2018, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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)
2021
2022
2023
2024
2025
11. Debt, Net
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")
Opco debt:
Revolving credit facility
Senior Notes
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 issuance costs
Total debt, net
Less: current portion of long-term debt
Total long-term debt, net
Estimated
Amortization Expense
$
1,155
525
1,199
1,037
950
December 31,
2020
2019
300,000 $
300,000
— $
—
— $
6,780
7,094
9,458
18,013
24,016
50,738
63,423
16,047
20,059
68,524
79,945
17,464
177,880 $
477,880 $
20,375
224,056
524,056
(6,381)
(7,858)
471,499 $
516,198
(39,055)
(45,776)
432,444 $
470,422
$
$
$
$
$
$
$
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Table of Contents
NRP LP Debt
2025 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. 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, 2020 and 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).
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, 2020 and 2019, 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%.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the years ended December 31, 2020 and 2019, the Partnership did not have any borrowings outstanding under the
Opco Credit Facility and had $100.0 million in available borrowing capacity at both December 31, 2020 and 2019. Opco will
incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay
all amounts outstanding under the Opco Credit Facility at any time without penalty.
The Opco Credit Facility contains 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 $364.5
million and $399.7 million classified as mineral rights, net and other long-term assets, net on the Partnership’s Consolidated
Balance Sheets as of December 31, 2020 and 2019, respectively. The collateral includes (1) the equity interests in all of Opco’s
wholly owned subsidiaries, other than BRP LLC and 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, 2020 and 2019, the Opco Senior Notes had cumulative principal balances of $177.9
million and $224.1 million, respectively. Opco made mandatory principal payments on the Opco Senior Notes of $46.2 million,
$117.4 million and $80.7 million during the years ended December 31, 2020, 2019 and 2018, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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, 2020.
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 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)
2021
2022
2023
2024
2025
Thereafter
NRP LP
Opco
Senior Notes
Senior Notes
Credit Facility
Total
$
— $
39,396 $
— $
—
—
—
300,000
—
39,396
39,396
31,028
14,332
14,332
—
—
—
—
—
39,396
39,396
39,396
31,028
314,332
14,332
$
300,000 $
177,880 $
— $
477,880
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
12. Fair Value Measurements
Fair Value of Financial Assets and Liabilities
The Partnership’s financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The
carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents approximate fair value due to their
short-term nature. The Partnership uses available market data and valuation methodologies to estimate the fair value of its debt
and contract receivable.
The following table shows the carrying value and estimated fair value of the Partnership's debt and contract receivable:
(In thousands)
Debt:
NRP 2025 Senior Notes
Opco Senior Notes (1)
Opco Credit Facility
Assets:
Contract receivable, net (current and
long-term) (2)
December 31,
2020
2019
Fair Value
Hierarchy Level
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
1
3
3
3
$
295,160 $
274,500 $
294,084 $
269,250
176,339
162,760
222,114
201,090
—
—
—
—
$
35,313 $
27,025 $
38,945 $
33,460
(1) The fair value of the Opco Senior Notes are estimated by management using quotations obtained for the NRP 2025 Senior
Notes on the closing trading prices near period end, which were at 92% of par value at December 31, 2020.
(2) The fair value of the Partnership's contract receivable is determined based on the present value of future cash flow
projections related to the underlying asset at a discount rate of 15% at December 31, 2020.
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, 2020 and 2019.
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 9. Mineral Rights, Net and Note 10. Intangible Assets, Net for
additional disclosures related to the fair value associated with the impaired assets.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
13. 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,
2020
2019
2018
$
6,294 $
6,436 $
3,539
3,548
6,170
3,658
The Partnership had accounts payable to QMC of $0.4 million on its Consolidated Balance Sheets as of December 31,
2020 and 2019 and $0.3 million and $0.1 million of accounts payable to WPPLP as of December 31, 2020 and 2019,
respectively.
During the years ended December 31, 2020, 2019 and 2018, the Partnership recognized $0.4 million, $4.0 million and
$5.4 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, 2020, the Partnership had $0.3 million of
other long-term assets, net on its Consolidated Balance Sheets related to a prepaid royalty for this agreement. At December 31,
2019, the Partnership had $0.1 million of accounts payable to WPPLP on its Consolidated Balance Sheets related to this
agreement.
Industrial Minerals Group LLC
Prior to December 31, 2019, Corbin J. Robertson, III, a Director of GP Natural Resource Partners LLC, held a minority
ownership interest in Industrial Minerals Group LLC (“Industrial Minerals”), which, through its subsidiaries, leases one of
NRP’s coal royalty properties in Central Appalachia. Coal royalty related revenues from Industrial Minerals totaled $1.7
million and $0.8 million for the years ended December 31, 2019 and 2018, respectively. The Partnership had accounts
receivable from Industrial Minerals of $0.7 million on its Consolidated Balance Sheets as of December 31, 2019.
Quinwood Coal Company Royalty
Quinwood Coal Partners LP (“Quinwood”), an entity controlled by Corbin J. Robertson, III, leases two coal properties
from NRP in Central Appalachia. Coal related revenues from Quinwood totaled $0.0 million, $0.2 million and $0.0 million for
the years ended December 31, 2020, 2019 and 2018, respectively.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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, 2020, 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 for the
year ended December 31, 2018.
14. 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 (1) (2)
Alpha Metallurgical
Resources, Inc. (formerly
Contura Energy Inc.) (1) (3)
2020
For the Year Ended December 31,
2019
2018
Revenues
Percent
Revenues
Percent
Revenues
Percent
$
35,704
26 % $
58,923
23 % $
54,595
22 %
33,227
24 %
40,743
16 %
24,580
10 %
(1) Revenues from Foresight and Alpha Metallurgical Resources, Inc. (formerly Contura Energy Inc.) are included within the
Partnership's Coal Royalty and Other segment.
(2)
(3)
In June 2020, the Partnership entered into lease amendments with Foresight pursuant to which Foresight agreed to pay
NRP fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation
infrastructure fee agreements between the Partnership and Foresight for calendar years 2020 and 2021.
In the fourth quarter of 2018, Contura Energy and Alpha Natural Resources merged. Revenues during the year ended
December 31, 2020 and 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. In February 2021, Contura Energy
changed its name to Alpha Metallurgical Resources, Inc.
15. 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.
In November 2019, the District Court of Harris County, Texas, 157th Judicial District, issued a ruling in the contingent
consideration payment dispute that Anadarko Holding Company and its subsidiary, Big Island Trona Company (together,
"Anadarko") brought against NRP in July 2017. The Trial Court ruled in NRP's favor in all respects and ordered that Anadarko
take nothing. Anadarko did not appeal the trial court ruling, and accordingly this lawsuit was concluded in the first quarter of
2020 with no liability to the Partnership.
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
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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, 2020. 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.
16. 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 either vest 3 years following the grant date or vest ratably over the 3 year period
following the grant date. Awards granted to non-employee directors vest over a 1 year period. 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 settlement date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases
employment prior to vesting.
The awards granted in 2020, 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, 2020, 2019 and 2018 were $3.5 million, $5.4
million and $2.2 million, respectively. Total unit-based compensation expense associated with these awards was $3.6 million,
$2.4 million and $1.1 million for the years ended December 31, 2020, 2019 and 2018, respectively, and is included in general
and administrative expenses and operating and maintenance expenses on the Partnership's Consolidated Statements of
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Comprehensive Income (Loss). The unamortized cost associated with unvested outstanding awards as of December 31, 2020 is
$3.7 million, which is to be recognized over a weighted average period of 1.6 years. The unamortized cost associated with
unvested outstanding awards as of December 31, 2019 was $3.5 million.
A summary of the unit activity in the outstanding grants during 2020 is as follows:
(In thousands)
Outstanding grants at January 1, 2020
Granted
Fully vested and issued
Forfeitures
Outstanding at December 31, 2020
17. Financing Transaction
Common Units
Weighted
Average
Exercise Price
157 $
203 $
— $
(5) $
355 $
37.48
17.20
—
17.20
26.20
The Partnership owns rail loadout and associated infrastructure at the Sugar Camp mine in the Illinois Basin operated by a
subsidiary of Foresight. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight 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 $5.0 million due to the
Partnership in 2020 and 2021 is included in the fixed cash payments from Foresight resulting from contract modifications
entered into during the second quarter of 2020 as discussed in Note 14. Major Customers. 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.
18. Credit Losses
The Partnership is exposed to credit losses through collection of its trade receivables resulting from contracts with
customers and a long-term receivable resulting from a financing transaction with a customer. The Partnership records an
allowance for current expected credit losses on these receivables based on the loss-rate method. NRP assessed the likelihood of
collection of its receivables utilizing historical loss rates, current market conditions that included the estimated impact of the
global COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or
circumstances of individual customers and properties. Examples of these facts or circumstances include, but are not limited to,
contract disputes or renegotiations with the customer and evaluation of short and long-term economic viability of the contracted
property. For its long-term contract receivable, management reverts to the historical loss experience immediately after the
reasonable and supportable forecast period ends.
As of December 31, 2020, NRP recorded the following current expected credit loss (“CECL”) related to its receivables
and long-term contract receivable:
(In thousands)
Receivables
Long-term contract receivable
Total
Gross
CECL Allowance
Net
$
$
18,512 $
(2,358) $
34,818
(1,554)
53,330 $
(3,912) $
16,154
33,264
49,418
NRP recorded $0.0 million in operating and maintenance expenses on its Consolidated Statement of Comprehensive
Income (Loss) related to the change in CECL allowance during the year ended December 31, 2020.
NRP has procedures in place to monitor its ongoing credit exposure through timely review of counterparty balances
against contract terms and due dates, account and financing receivable reconciliations, bankruptcy monitoring, lessee audits and
dispute resolution. The Partnership may employ legal counsel or collection specialists to pursue recovery of defaulted
receivables.
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19. Leases
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
As of December 31, 2020, 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 and 2020, 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 Sheets 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 long-term assets, net and other non-current liabilities, respectively, on its
Consolidated Balance Sheets totaled $3.5 million at both December 31, 2019 and 2020. During the years ended December 31,
2020 and 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 Statements of Comprehensive Income
(Loss).
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)
2021
2022
2023
2024
2025
After 2025
Total lease payments (1)
Less: present value adjustment (2)
Total operating lease liability
December 31, 2020
$
$
$
483
483
483
483
483
11,114
13,529
(10,033)
3,496
(1) The remaining lease term of the Partnership's operating lease is 28 years.
(2) The present value of the operating lease liability on the Partnership's Consolidated Balance Sheets 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.
20. 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 Sheet at December 31, 2019:
(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
Construction
Aggregates
NRP
Oil and Gas
Total
$
$
$
$
— $
— $
1,706 $
1,706 $
1,706
1,706
42 $
23
65 $
— $
—
— $
42
23
65
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
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
—
—
130,018 $
134 $
130,152
(38) $
17,824 $
— $
(137) $
(38)
17,687
116,066
18,400
(3)
13,414
147,877
117,702
12,218
232
Capital expenditures related to the Partnership's discontinued operations were $10.9 million during the year ended
December 31, 2018, of which $0.9 million were funded with accounts payable or accrued liabilities.
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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, 2020. 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, 2020 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, 2020 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, 2020,
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, 2020, 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, 2020, 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, 2020 and 2019, 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, 2020, and the related notes and our report dated March 15, 2021 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
March 15, 2021
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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
Alexander D. Greene
S. Reed Morian
Paul B. Murphy, Jr.
Richard A. Navarre
Corbin J. Robertson, III
Stephen P. Smith
Leo A. Vecellio, Jr.
Position with the General Partner
Age
73 Chairman of the Board and Chief Executive Officer
59 President and Chief Operating Officer
46 Chief Financial Officer and Treasurer
52 Executive Vice President
46 Vice President, General Counsel and Secretary
65 Senior Vice President, Chief Engineer
61 Director
62 Director
75 Director
61 Director
60 Director
50 Director
60 Director
74 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.
Mr. Robertson is also Chief Executive Officer and a member of the Board of Managers of Pocahontas Royalties 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 was named Executive Vice President of GP Natural Resource Partners LLC in February 2021, after
serving 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. 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 serves as a member of the Board of Directors of Encova Mutual Insurance Company and the West
Virginia University Board of Governors.
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 was named Senior Vice President, Chief Engineer of GP Natural Resource Partners LLC in February
2021, after serving 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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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 Pocahontas Royalties, LLC. 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. He is currently serving on the Board of Directors of Gulf Capital Bank in Houston.
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 $18 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 CEO and President of Covia Holdings, a leading provider of high quality minerals and material solutions for the
industrial and energy markets. From 1993 until 2012, Mr. Navarre held several executive positions with Peabody Energy
Corporation, including President-Americas, President and Chief Commercial Officer, Executive Vice President of Corporate
Development and Chief Financial Officer. Mr. Navarre serves on the Board of Directors of Civeo Corporation, where he serves
as Chairman, Covia Holdings (where he served as Chairman from 2018 through 2020), and Arch Resources, 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 Analytics 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 seven times in 2020. During 2020, 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 several times in executive session in 2020. Mr. Vecellio was the
presiding director at those meetings. 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, 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.
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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 2020, the
Audit Committee met six times.
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 2020, 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, 2020 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 2020, 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, 2020, 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. Navarre and Mr. Smith. Mr. Navarre joined the CNG committee effective August 7, 2020.
Russell D. Gordy served as a member of the CNG Committee in 2020 until his resignation from the board effective August 6,
2020. During 2020, the CNG Committee met two 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 2020, 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
Smaller Reporting Company Status
We are a “smaller reporting company,” as such term is defined in the rules promulgated under the Securities Exchange
Act of 1934, as amended, and we have elected to provide our executive compensation disclosure in accordance with such rules.
Accordingly, we have provided compensation disclosure for our principal executive officer and the two most highly
compensated executive officers other than our principal executive officer and have omitted the compensation discussion and
analysis and the compensation committee reports as permitted by the rules.
Summary Compensation Table
The following table sets forth the amounts reimbursed to affiliates of our general partner for our named executive officers’
compensation for the years ended December 31, 2019 and 2020:
Name and Principal Position
Year
Salary ($)
Bonus ($)
Corbin J. Robertson, Jr.—Chief Executive Officer
Stock Awards
($) (1)
All Other
Compensation
($) (2)
Total ($)
2020
2019
—
—
825,188
938,868
1,210,467
1,306,222
—
—
2,035,655
2,245,090
Craig W. Nunez—President and Chief Operating Officer
2020
2019
515,000
500,000
358,778
408,204
657,866
653,111
17,100
16,800
1,548,744
1,578,115
Christopher J. Zolas—Chief Financial Officer
2020
2019
365,000
355,000
203,423
284,000
276,989
492,581
17,100
16,800
862,512
1,148,381
(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 16. 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.
Narrative to the Summary Compensation Table
As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a
typical public corporation. Our named executive officers are based in Houston, Texas and employed by Quintana Minerals
Corporation (“Quintana”). Quintana is controlled by our Chairman and Chief Executive Officer and is an affiliate of NRP.
While our named executive officers are employed by an affiliate 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.
Base Salaries
With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our named
executive officers are paid an annual base salary by Quintana for services rendered to us by the named executive officers during
the fiscal year. We then reimburse Quintana based on the time allocated by each named 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.
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Short-Term Cash Incentive Compensation
Each named executive officer received a discretionary short-term cash incentive award approved in February 2021 by the
CNG Committee. With respect to 2020, the CNG Committee, using recommendations from its independent compensation
consultant, Longnecker & Associates, determined that cash bonuses would be paid based on a percentage of base salary. In
addition, the CNG Committee determined that it would consider certain criteria to determine bonus amounts, 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 Partnership.
Long-Term Incentive Compensation
Phantom units awarded to named executive officers under the Natural Resource Partners L.P. 2017 Long-Term Incentive
Plan (the “2017 Plan”) in 2020 are described in greater detail in the table and associated narrative below.
Perquisites and Other Personal Benefits
Quintana maintains employee benefit plans that provide our named 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 the company costs are reimbursed by us to the extent the employee allocates time to our business.
In 2020, Quintana maintained tax-qualified 401(k) plans. During 2020, Quintana 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 are reimbursed by us based on the time allocated by the employee to our business. Neither NRP nor Quintana
maintains a pension plan or a defined benefit retirement plan.
Employment Agreements Contracts and Potential Payments Upon a Termination of Employment or a Change in Control
None of our named executive officers have an employment agreement. All phantom units awarded under the 2017 Plan to
date will vest upon a change in control of NRP and upon the death or disability of the named executive officer. Phantom units
awarded in 2020 will also vest upon termination of employment of the named executive officer without “cause” or for “good
reason.”
Outstanding Equity Awards at December 31, 2020
Awards made to our named executive officers under the 2017 Plan have been made in phantom units that settle in
common units on a one-for-one basis with tandem distribution equivalent rights (“DERs”). The phantom unit awards made in
2020 time-vest ratably over the three-year period following the grant date and accrue DERs to be paid in cash upon each
settlement. Phantom units awarded in 2018 and 2019 time-vest on the third anniversary of the grant date and accrue DERs to be
paid in cash upon settlement. The table below shows the total number of outstanding phantom unit awards under the 2017 Plan
held by each named executive officer at December 31, 2020:
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Unvested 2017 Plan Phantom Units
116,267 (2)
61,194 (3)
33,739 (4)
Aggregate Market Value of Unvested
2017 Plan Phantom Units (1)
$
1,598,671
841,418
463,911
(1) Based on a unit price of $13.75, the closing price for the common units on December 31, 2020
(2)
(3)
(4)
37,851 phantom units vesting in February 2021, 54,957 phantom units vesting in February 2022 and 23,459 phantom
units vesting in February 2023.
19,946 phantom units vesting in February 2021, 28,498 phantom units vesting in February 2022 and 12,750 phantom
units vesting in February 2023.
11,125 phantom units vesting in February 2021, 17,246 phantom units vesting in February 2022 and 5,368 phantom units
vesting in February 2023.
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Directors’ Compensation for the Year Ended December 31, 2020
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 2020 consisted of a $75,000 cash retainer and an award of phantom units under the 2017 Plan. The phantom units
awarded to Board members in 2020 vest after one year; 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 the chairman of
the audit, compensation, nominating and governance and conflicts committees received an additional $20,000, $15,000 and
$10,000, respectively, for acting as chairman.
The table below shows the directors’ compensation for the year ended December 31, 2020:
Name of Director
Russell D. Gordy (2)
S. Reed Morian
Richard A. Navarre (3)
Corbin J. Robertson, III
Stephen P. Smith (4)
Leo A. Vecellio, Jr.
Paul B. Murphy, Jr.
Galdino J. Claro
Alexander D. Greene (5)
Fees Earned or Paid in Cash
2017 Plan Common Unit Awards (1)
Total Compensation
$
60,000 $
— $
75,000
96,997
75,000
105,000
100,000
75,000
85,000
—
84,813
84,813
84,813
84,813
84,813
84,813
84,813
—
60,000
159,813
181,810
159,813
189,813
184,813
159,813
169,813
—
(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 16 to the audited consolidated financial statements included elsewhere in this Annual
Report on Form 10-K. All of the phantom units reported in this column were outstanding on December 31, 2020 and will
vest on February 13, 2021.
(2) Mr. Gordy resigned from the Board effective August 7, 2020. Mr. Gordy served on our compensation, nominating, and
governance committee in 2020 until his resignation from the Board.
(3) Mr. Navarre elected to defer settlement of his common units awarded under the 2017 Plan in 2018 and 2019 until 90 days
following his retirement or earlier departure from the Board. Mr. Navarre joined the compensation, nominating, and
governance committee effective August 7, 2020. As of December 31, 2020, 9,285 phantom units previously awarded to
Mr. Navarre were outstanding but only 4,931 were unvested.
(4) Mr. Smith elected to defer settlement of his common units awarded under the 2017 Plan in 2018, 2019 and 2020 until 90
days following his retirement or earlier departure from the Board. As of December 31, 2020, 9,285 phantom units
previously awarded to Mr. Smith were outstanding but only 4,931 were unvested.
(5) Mr. Greene did not receive Board compensation as the Blackstone designee to the Board.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following tables set forth, as of March 1, 2021, 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)
Steven A. Tananbaum. (7)
Craig W. Nunez
Christopher J. Zolas
Galdino J. Claro
Alexander D. Greene
S. Reed Morian (8)
Paul B. Murphy, Jr.
Richard A. Navarre (9)
Corbin J. Robertson III (10)
Stephen P. Smith (11)
Leo A. Vecellio, Jr.
Directors and Officers as a Group (12)
*
Less than one percent.
Common
Units
Percentage of
Common
Units (1)
2,434,352
1,739,007
1,727,986
1,028,351
984,950
812,089
12,097
6,970
9,045
—
625,444
8,738
5,931
243,587
355
11,285
19.7 %
14.1 %
14.0 %
8.3 %
8.0 %
6.6 %
*
*
*
—
5.1 %
*
*
2.0 %
*
*
3,373,897
27.3 %
(1)
12,351,306 common units issued and outstanding as of March 1, 2021.
(2) Mr. Robertson, Jr. may be deemed to beneficially own 528,818 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, Jr.’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.
(5) According to a Schedule 13G filing with the SEC on January 11, 2021, JPMorgan Chase & Co. holds sole voting power
and sole dispositive power with respect to 1,028,351 common units. The business address of JPMorgan Chase & Co. is
383 Madison Avenue., New York, NY 10179.
(6) According to a Schedule 13G filing with the SEC on February 11, 2021, The Goldman Sachs Group holds shared voting
power and shared dispositive power with respect to 984,950 common units in the Partnership. The business address of
The Goldman Sachs Group is 200 West Street, New York, NY 10282.
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(7) According to a Schedule 13G filing with the SEC on February 11, 2021, Steven A. Tananbaum holds sole voting power
and sole dispositive power with respect to 251,639 common units in the Partnership and shared voting power and shared
dispositive power with respect to 560,450 common units in the Partnership. Mr. Tananbaum serves as the managing
member of GoldenTree Asset Management LLC (“IMGP”), which serves as the general partner of GoldenTree Asset
Management LP. GoldenTree Asset Management LP and IMGP hold shared voting power and shared dispositive power
with respect to 560,450 common units in the Partnership. The business address of Steven A. Tananbaum, GoldenTree
Asset Management LP and IMGP is 300 Park Avenue, 21st Floor, New York, NY 10022.
(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) Does not include 4,354 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Navarre has elected
to defer settlement of until 90 days following the date that he no longer serves on NRP’s board.
(10) 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.
(11) Does not include 9,285 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Smith has elected to
defer settlement of until 90 days following the date that he no longer serves on NRP’s board. Mr. Smith may be deemed to
beneficially own 355 common units owned by the SP Smith 2002 Revocable Trust.
(12) NRP’s directors and executive officers as a group consists of 14 individuals.
Name of Beneficial Owner
The Blackstone Group Inc. (1)
GoldenTree Asset Management, LP (2)
Preferred Units
Percentage of
Preferred Units
146,808
110,749
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
Relationships with Entities Associated with Corbin J. Robertson, Jr.
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 (and except as described
below under "—Pocahontas Royalties LLC"), 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.
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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 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.
Pocahontas Royalties LLC
On February 28, 2020, Pocahontas Royalties LLC (“Pocahontas Royalties”) completed the acquisition of a private
company that owns approximately one million acres of mineral reserves and leases coal reserves to coal mine operators in
Central Appalachia. Pocahontas Royalties is controlled by Corbin J. Robertson, Jr. and members of his family. Reed Morian,
one of the directors of GP Natural Resource Partners LLC, also serves on the Board of Managers of Pocahontas Royalties.
In connection with the closing of the acquisition, we and Pocahontas Royalties entered into a limited waiver of the
omnibus agreement pursuant to which we waived the provision of the omnibus agreement that restricts Mr. Robertson and his
affiliates (other than NRP) from owning, operating or investing in fee coal reserves in the United States with an aggregate fair
market value in excess of $75 million. Mr. Robertson had previously offered NRP the opportunity to participate in the
acquisition and we determined, after due consideration, not to participate.
In addition, on February 28, 2020, we and Pocahontas Royalties entered into a right of first offer agreement pursuant to
which Pocahontas Royalties granted us the exclusive right of first offer to purchase any assets (or entities holding such assets)
proposed to be sold at any time by Pocahontas Royalties or any of its subsidiaries with a fair market value exceeding $2 million
(individually or in the aggregate), excluding surface acreage, assets or rights (other than surface rights that are appurtenant to or
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necessary for the development of mineral reserves). Provided that Pocahontas Royalties has provided us the opportunity to
make a first offer within the time periods specified in the agreement, Pocahontas Royalties will be under no obligation to accept
any offer timely made by us and may determine, in its sole discretion, to consummate a transaction with a third party free and
clear of any obligations to us.
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.
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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.
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 leases two coal properties
from us in Central Appalachia. During the year ended December 31, 2020, we recorded $0.0 million in coal royalty revenues
from Quinwood and received less than $0.1 million in cash related to royalty and property tax payments. 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.
Prior to December 31, 2019, Mr. Robertson III held a minority ownership interest in Industrial Minerals Group LLC
(“Industrial Minerals”), which, through its subsidiaries, leases one 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.
Preferred Unitholder 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 4.
Class A Convertible Preferred Units and Warrants" elsewhere in this Annual Report on Form 10-K.
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. We paid approximately $0.8 million to Western Pocahontas
under the lease during both years ended December 31, 2020 and 2019.
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. We paid approximately $0.1 million in interest and fees under the credit facility to
Cadence Bank, N.A during both years ended December 31, 2020 and 2019.
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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 and Pocahontas Royalties) 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.
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;
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•
•
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.
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.
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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.
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
and Pocahontas Royalties) 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, 2020 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 2020 and 2019. 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)
2020
2019
$
785,750 $
505,915
1,070,206
533,083
(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.
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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.
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.
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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.
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
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
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).
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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. (incorporated by reference to Exhibit 4.25 to
Annual Report on Form 10-K filed on February 27, 2020).
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).
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Exhibit
Number
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13+
10.14+
10.15+
10.16+
10.17+
10.18+
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).
Master Amendment and Supplement to Coal Mining and Transportation Lease Agreements and Parent Guaranty
dated June 30, 2020 by and among NRP (Operating) LLC, WPP LLC, Hod LLC, Independence Land Company,
LLC, Williamson Transport LLC, Foresight Energy LP, Foresight Energy GP LLC, Foresight Energy LLC,
Macoupin Energy, LLC, Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC, Foresight
Energy Resources LLC, and Foresight Energy Operating LLC (incorporated by reference to Exhibit 10.1 to
Current Report on Form 8-K filed on July 1, 2020).
Limited Waiver dated February 28, 2020 by Natural Resource Partners L.P., GP Natural Resource Partners LLC,
NRP (GP) LP, and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form
8-K filed on March 3, 2020).
Right of First Offer Agreement dated as of February 28, 2020 by and among Pocahontas Royalties LLC, Natural
Resource Partners L.P., GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC.
(incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March 3, 2020).
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) (incorporated by reference to
Exhibit 10.13 to Annual Report on Form 10-K filed on February 27, 2020).
Form of Phantom Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit
10.14 to Annual Report on Form 10-K filed on February 27, 2020).
Form of Phantom Unit Award Agreement (Directors with Deferral Election) (incorporated by reference to Exhibit
10.15 to Annual Report on Form 10-K filed on February 27, 2020).
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, 2020 and 2019 and for the years ended
December 31, 2020, 2019 and 2018.
Inline XBRL Instance Document
101.INS*
101.SCH* Inline XBRL Taxonomy Extension Schema Document
101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* Inline XBRL Taxonomy Extension Labels Linkbase Document
116
Table of Contents
101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*
Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information
contained in Exhibits 101)
*
**
+
Filed herewith
Furnished herewith
Management compensatory plan or arrangement
117
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: March 15, 2021
Date: March 15, 2021
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)
118
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: March 15, 2021
Date: March 15, 2021
Date: March 15, 2021
Date: March 15, 2021
Date: March 15, 2021
Date: March 15, 2021
Date: March 15, 2021
Date: March 15, 2021
/s/ GALDINO J. CLARO
Galdino J. Claro
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
119
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: March 15, 2021
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: March 15, 2021
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, 2020 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.
By:
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.
/s/ Corbin J. Robertson, Jr.
Corbin J. Robertson, Jr.
Chief Executive Officer
Date: March 15, 2021
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, 2020 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: March 15, 2021
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 March 15, 2021, 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, 2020.
/s/ Ernst & Young LLP
Houston, Texas
March 15, 2021
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 L.P., of our report dated March 15, 2021,
relating to the financial statements of Ciner Wyoming LLC as of December 31, 2020 and 2019, and for the three years in the
period ended December 31, 2020, appearing in this Annual Report on Form 10-K of Natural Resource Partners L.P. for the year
ended December 31, 2020.
Exhibit 23.2
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 15, 2021
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
Rivervista Mining, LLC
Deepwater Transportation, LLC
NRP Trona LLC
BRP LLC
BRP Minerals LLC
CoVal Leasing Company, LLC
Exhibit 99.1
Ciner Wyoming LLC
(A Majority-Owned Subsidiary of Ciner Resources LP)
Financial Statements as of December 31, 2020 and 2019 and for the Years Ended
December 31, 2020, 2019, and 2018, 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, 2020 AND 2019
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED
DECEMBER 31, 2020, 2019 AND 2018
STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 2020, 2019 AND 2018
STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018
NOTES TO THE FINANCIAL STATEMENTS
Page
Number
3
5
6
7
8
9
2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To 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, 2020 and
2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2020, 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and
we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the
accounts or disclosures to which it relates.
Agreements and Transactions with Affiliates – Refer to Notes 1, 2, 8, 12, and 13 to the financial statements
3
Critical Audit Matter Description
The Company is a subsidiary in a global group structure and agreements directly between the Company and other affiliates, or
indirectly between affiliates that the Company does not control, can have a significant impact on recorded amounts or
disclosures in the Company's financial statements, including any commitments and contingencies between the Company and
affiliates or, potentially, third parties. Performing audit procedures to evaluate the Company’s identification of upstream
affiliate relationships, transactions, and commitments and contingencies outside of the U.S. and the impact of such matters on
the financial statements represents a critical audit matter because of the increased auditor judgment necessary to perform audit
procedures related to these matters and evaluate the results of those procedures.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Company’s identification of upstream affiliate relationships, transactions, and commitments
and contingencies outside of the U.S. and the impact of such matters on the financial statements included the following, among
others:
• We tested the effectiveness of controls over the Company’s affiliate process, including controls over the identification of
the Company’s affiliate relationships, transactions, and commitments and contingencies outside of the U.S.
• We read publicly available financial filings and news sources related to the Company and its affiliates outside of the U.S.
and listened to the parent company (Ciner Resources LP) quarterly investor relations calls for information related to
potential new affiliates and transactions between the Company and affiliates.
• We inspected director and executive officer questionnaires from the parent company directors and officers to identify any
affiliate matters.
• We searched the general ledger for potential transactions with affiliates.
• We read significant new or amended agreements and contracts of the Company to identify new affiliate relationships,
transactions, or commitments and contingencies, and evaluated management’s analyses regarding the accounting and
disclosure of such arrangements.
• We inquired of executive officers, key members of management, and the Board of Managers regarding affiliate
relationships, transactions and commitments and contingencies.
• We confirmed with the ultimate parent company that the affiliate relationships, transactions, and commitments and
contingencies identified and disclosed by the Company were complete.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 15, 2021
We have served as the Company’s auditor since 2008.
4
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
BALANCE SHEETS
AS OF DECEMBER 31, 2020 AND 2019
(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:
Current portion of long-term debt
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 income (loss)
Total members' equity
2020
2019
$
364 $
86,697
40,613
33,456
3,590
13,684
95,115
35,963
24,193
1,741
164,720
170,696
268,590
258,121
25,418
24,266
$
458,728 $
453,083
$
2,983 $
16,393
2,865
33,072
—
14,163
3,215
37,961
55,313
55,339
127,069
129,500
8,707
8,587
191,089
193,426
136,459
131,108
72
135,423
130,113
(5,879)
267,639
259,657
TOTAL LIABILITIES AND MEMBERS' EQUITY
$
458,728 $
453,083
See notes to financial statements.
5
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018
(In thousands of dollars)
SALES - AFFILIATES
SALES - OTHERS
Total net sales
COST OF PRODUCTS SOLD
FREIGHT COSTS
Total cost of products sold
GROSS PROFIT
2020
2019
2018
$
177,891 $
214,340
392,231
315,847 $
206,996
522,843
213,721
123,672
247,790
143,341
253,345
233,414
486,759
243,562
139,144
337,393
391,131
382,706
54,838
131,712
104,053
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES
17,398
18,404
17,698
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS
LITIGATION SETTLEMENT GAIN
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest income
Interest expense
Other expense, net
Total other expense
NET INCOME
946
—
1,553
2,106
—
(27,500)
36,494
111,755
111,749
145
(5,305)
(304)
350
(5,893)
(57)
1,871
(5,058)
(205)
(5,464)
(5,600)
(3,392)
31,030
106,155
108,357
Income (loss) on derivative financial instruments
5,951
1,612
(282)
COMPREHENSIVE INCOME
$
36,981 $
107,767 $
108,075
See notes to financial statements.
6
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF MEMBERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018
(In thousands of dollars)
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
Allocation of net income
Capital distribution to members
Other comprehensive income
Balance at December 31, 2020
Ciner
Resources LP
Natural
Resource
Partners LP
Accumulated
Other
Comprehensive
Income (Loss)
Total
Members'
Equity
$
$
$
$
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
15,826
(14,790)
—
15,205
(14,210)
—
—
—
5,951
31,030
(29,000)
5,951
136,459 $
131,108 $
72 $
267,639
See notes to financial statements.
7
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
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
2020
2019
2018
$
31,030 $
106,155 $
108,357
28,494
8
322
8,418
(4,650)
(9,757)
(450)
2,155
2,489
(382)
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
57,677
106,410
165,194
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(42,218)
(65,350)
(39,419)
Net cash used in investing activities
(42,218)
(65,350)
(39,419)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on revolving credit facility
Borrowings on other long-term debt
Repayments on revolving credit facility
Repayments on other long-term debt
Debt issuance costs
Cash distribution to members
211,500
30,000
(238,500)
(2,225)
(554)
(29,000)
102,000
—
(71,500)
—
—
(65,000)
104,000
—
(143,000)
(11,400)
—
(95,000)
Net cash used in financing activities
(28,779)
(34,500)
(145,400)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
(13,320)
6,560
(19,625)
CASH AND CASH EQUIVALENTS:
Beginning of year
End of year
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid during the year
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES :
Capital expenditures on account
13,684
7,124
26,749
364 $
13,684 $
7,124
5,115 $
5,476 $
5,141
1,977 $
6,786 $
14,002
$
$
$
See notes to financial statements.
8
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
NOTES TO FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2020 AND 2019 AND FOR THE YEARS ENDED DECEMBER 31, 2020, 2019, AND 2018
(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, 2020, 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 Şirketi ("Akkan"). Akkan is directly and wholly owned by Turgay Ciner, the Chairman of
the Ciner Group ("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 mining and
processing activities take place in one facility located in Green River, Wyoming. All our soda ash processed is sold to
various domestic customers, and to American Natural Soda Ash Corporation ("ANSAC"), which was an affiliate for
export sales through the year ended December 31, 2020. Ciner Corp is the exclusive sales agent for the Partnership, and a
member of ANSAC. Effective as of the end of day on December 31, 2020 Ciner Corp exited ANSAC.
ANSAC Exit - On November 9, 2018, Ciner Corp delivered a notice to terminate its membership in ANSAC as part of its
strategic initiative to gain better direct access and control of international customers and logistics and the ability to
leverage the expertise of Ciner Group, the world’s largest natural soda ash producer. Such termination was originally
expected to be effective as of the end of day on December 31, 2021. On July 27, 2020, ANSAC and the members thereof
entered into an agreement, effective as of July 24, 2020, that, among other things, terminated Ciner Corp’s membership in
ANSAC effective as of December 31, 2020 (the “ANSAC termination date”), a year earlier than previously announced
(the “ANSAC Early Exit Agreement”). Effective as of the end of day on December 31, 2020, Ciner Corp exited ANSAC.
As of January 1, 2021, Ciner Corp began managing the sales and marketing efforts for exports with the ANSAC exit
being complete. Ciner Corp is leveraging the distributor network established by Ciner Group while independently
reviewing current and potential distribution partners to optimize our reach into each market.
9
In connection with the settlement agreement with ANSAC, there are sales commitments to ANSAC in 2021 and 2022
where Ciner Corp will continue to sell, at substantially lower volumes, product to ANSAC for export sales purposes, with
a fixed rate per ton selling, general and administrative expense, and will also purchase a limited amount of export logistics
services in 2021. Through in part the Company’s affiliates, the Company has amongst other things: (i) obtained its own
international customer sales arrangements for 2021, (ii) obtained third-party export port services, and (iii) chartered and
executed its own international product delivery.
Historically, by design and prior to Ciner Corp’s exit from ANSAC, ANSAC managed most of our international sales,
marketing and logistics, and as a result, was our largest customer for the years ended December 31, 2020, 2019 and 2018,
accounting for 45.4%, 60.4% and 52.0%, respectively, of our net sales. Although ANSAC was our largest customer for
the aforementioned periods, we anticipate that the impact of Ciner Corp’s exit from ANSAC on our net sales, net income
and liquidity will be limited. We made this determination primarily based upon the belief that we will continue to be one
of the lowest cost producers of soda ash in the global market. With a low-cost position combined with better direct access
and control of our customers and logistics and the ability to leverage Ciner Group’s expertise in these areas, we believe
we will be able to adequately replace these net ANSAC sales.
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.
Furthermore, we considered the impact of the COVID-19 pandemic on the use of estimates and assumptions used for
financial reporting. While our production is considered “essential”, the COVID-19 outbreak disrupted our customers and
customer segments, which had a negative impact on the demand for our products which adversely affected our operations.
In 2020, the decline in demand adversely impacted our sales and production volume, and price per ton. We experienced
an approximately 17.2% decline in production volumes and 19.5% decline in sales volumes when compared to our pre-
COVID-19 production and sales levels in 2019, respectively. Our international demand was impacted the most as
different countries dealt with different levels of the outbreak and shutdowns. In addition, our customers in the flat glass
and in particular the automotive business were significantly negatively impacted. At December 31, 2020, as we cannot
predict with confidence the duration or the scope of the COVID-19 pandemic and its impact on our operations, the
potential negative financial impact to our results cannot be reasonably estimated, but could be material. As a result of
these uncertainties, actual results could differ from those estimates and assumptions. If the economy or markets in which
we operate remain weaker than pre-COVID-19 levels or deteriorate further, our business, financial condition and results
of operations may be further materially and adversely impacted.
Revenue Recognition - The majority of the Company’s revenues are recognized upon satisfaction of our performance
obligations, that is, 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 we ship the product from our production
facility or third-party terminals, depending on the terms of the sales contract, rendering our performance obligation
fulfilled. For certain international customers, it is the point when the product is loaded on the vessel at the port.
Additionally, the Company has made an accounting policy election to account for shipping and handling activities as
fulfillment costs. We have one reportable segment and our revenue is derived from the sale of soda ash which is our sole
and primary good and service.
10
Performance Obligations. A performance obligation is a promise in a contract to transfer a distinct good or
service to the customer. A contract’s transaction price is allocated to each distinct performance 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 16, “Segment Reporting” for revenue
disaggregated into geographical regions.
Revenue 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).
11
•
•
Contract Assets. At the point of shipping, the Company has an unconditional right to payment generally
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 Sheets as of December 31, 2020 and December 31, 2019. There were no contract assets as
of December 31, 2020 and December 31, 2019.
Contract Liabilities. There may be situations where customers are required to prepay for freight and
insurance prior to shipment. The Company accounts for freight costs as fulfillment activities and
therefore, such prepayments are considered a part of the single obligation to provide soda ash. In such
instances, a contract liability for prepaid freight will be recorded.
Freight Costs - The Company includes freight costs billed to customers for shipments administered by the Company in
gross sales. The related freight costs incurred by the Company 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 - On January 1, 2020, we adopted the current expected credit loss (CECL) model in accordance with
ASU No. 2016-13, “Financial Instruments-Credit Losses (Topic 326)” as explained at Recently Issued and Adopted
Accounting Standards below. We determined the expected credit losses on initial recognition and at December 31, 2020
based on information about past events, including historical experience, current conditions, and reasonable and
supportable forecasts that affect the collectability of the reported amount.
Inventory - Inventory is carried at the lower of cost and net realizable value. 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. Net realizable value is defined as the estimated selling
price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.
• 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. If the inventory has been used within the preceding twelve months, it 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
5-10 years
12
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 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 three individual $12,500 swaps with an aggregate notional value
of $37,500 at December 31, 2020 and four individual $12,500 swaps with an aggregate notional value of $50,000 at
December 31, 2019. The swaps outstanding at December 31, 2020 have various maturities through 2023. At December
31, 2020, it is anticipated that approximately $196 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 natural gas financial forward contracts, designated as cash flow hedges, to mitigate
volatility in the price of natural gas related to a portion of the natural gas we consume. These contracts generally have
various maturities through 2024. These contracts had an aggregate notional value of $25,908 and $31,196 at December
31, 2020 and December 31, 2019, respectively. At December 31, 2020, it was anticipated that $661 of gains currently
recorded in accumulated other comprehensive income (loss) will be reclassified into earnings within the next twelve
months.
13
The following table presents the fair value of derivative assets and liabilities and the respective balance sheet locations as
of:
Assets
Liabilities
December 31,
2020
December 31,
2019
December 31,
2020
December 31,
2019
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
Other
current
assets
Other
current
assets
1,360
Interest rate swap contracts -
non-current
Natural gas forward contracts -
non-current
Total derivatives designated
as hedging instruments
Other
Non-
current
assets
—
876
Other
Non-
current
assets
Accrued
Expenses
Accrued
Expenses
Other
non-
current
liabilities
Other
non-
current
liabilities
$
196
Accrued
Expenses
$
855
Accrued
Expenses
700
2,400
1,077
—
Other
non-
current
liabilities
191
2,915
136
—
155
$
2,236
$
291
$
2,164
$
6,170
Income Tax - The Company is organized as a pass-through entity for federal income tax purposes and therefore are not
subject to federal or certain state income taxes. As a result, our 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 basis and financial reporting basis 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,
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. The liability was discounted using a weighted average credit-adjusted risk-free
rate 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-
14
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 Ciner Wyoming Credit Facility materially reflects the fair value as the rate is
variable and its key terms are similar to indebtedness with similar amounts, durations and credit risks. The carrying value
of Ciner Wyoming Equipment Financing Arrangement materially reflects the fair value as its key terms are similar to
indebtedness with similar amounts, durations and credit risks that are currently available to the Company. See Note 8
“Debt” for additional information on our debt arrangements.
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 March 15, 2021, the date the financial
statements were available to be issued. See Note 15 - Subsequent Events for additional information.
Recently Issued and Adopted Accounting Standards - 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. The Company adopted ASU 2016-13 effective January 1, 2020 and concluded there
was no 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
15
effective for periods beginning after December 15, 2019. The Company adopted ASU 2018-15 effective January 1, 2020
and concluded there was no material impact to the Company's financial statements.
Recent Guidance Not Adopted Yet - In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848):
Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) providing temporary
guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation
of the London Inter-bank Offered Rate (“LIBOR”), which was expected to occur on December 31, 2021. The
amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedging relationships, and other
transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance provides the
following optional expedients: (i) simplifies accounting analyses under current GAAP for contract modifications; (ii)
simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to
continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference
a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020
through December 31, 2022 by accounting topic The Company continues to evaluate ASU 2021-01 but does not expect a
material impact to the Company’s financial statements.
In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”). to clarify
that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price
alignment (commonly referred to as the discounting transition) are in the scope of ASC 848. The amendments also clarify
other aspects of the guidance in ASC 848 and addresses the effects of the cash compensation adjustment provided in the
discounting transition on certain aspects of hedge accounting. The guidance in ASC 848 also allows entities to make a
one-time election to sell and/or transfer to available for sale or trading any held-to-maturity debt securities that refer to an
interest rate affected by reference rate reform and were classified as held to maturity before January 1, 2020. The original
guidance and the recently issued ASU are effective as of their issuance dates. The relief provided is temporary and
generally cannot be applied to contract modifications that occur after December 31, 2022 or hedging relationships entered
into or evaluated after that date. However, the FASB has indicated that it will revisit the sunset date in ASC 848 after the
LIBOR administrator makes a final decision on a phaseout date. The LIBOR administrator recently extended the
publication of the overnight and the one-, three-, six- and 12-month USD LIBOR settings through June 30, 2023, when
many existing contracts that reference LIBOR will have expired. The Company continues to evaluate ASU 2021-01, but
does not expect any material impact to the Company's financial statements.
3. ACCOUNTS RECEIVABLE, NET
Accounts receivable, net as of December 31, 2020 and 2019 consisted of the following:
Trade receivables
Other receivables
Total
4. INVENTORY
Inventory as of December 31, 2020 and 2019 consisted of the following:
Raw materials
Finished goods
Stores inventory, current
Total
2020
2019
32,569 $
8,044
40,613 $
30,221
5,742
35,963
2020
2019
9,855 $
13,357
10,244
33,456 $
8,672
6,894
8,627
24,193
$
$
$
$
16
The increase in finished goods inventory at December 31, 2020 compared to December 31, 2019 is primarily due to the
Company building inventory to facilitate Ciner Corp’s exit from ANSAC and Ciner Corp providing the Company
international sales, marketing and logistics services after December 31, 2020.
5. PROPERTY, PLANT, AND EQUIPMENT, NET
Property, plant, and equipment as of December 31, 2020 and 2019 consisted of the following:
Land and land improvements
Depletable land
Buildings and building improvements
Computer hardware
Machinery and equipment
Furniture and fixtures
Total
Less accumulated depreciation, depletion and amortization
Total net book value
Construction in progress
Property, plant, and equipment, net
2020
$
192 $
2,957
163,483
5,328
680,159
1,411
853,530
(625,219)
228,311
40,279
268,590 $
$
2019
192
2,957
137,937
4,734
643,049
1,083
789,952
(622,545)
167,407
90,714
258,121
Depreciation, depletion and amortization expense on property, plant and equipment was $27,399, $26,175, and $27,731
for the years ended December 31, 2020, 2019 and 2018, respectively.
The decrease in construction in progress from December 31, 2019 to December 31, 2020 is due to the new co-generation
facility which started its construction in 2019 and completed in 2020.
6. OTHER NON-CURRENT ASSETS
Other non-current assets as of December 31, 2020 and 2019 consisted of the following:
Stores inventory, non-current
Internal-use software, net of accumulated amortization
Other
Total
2020
2019
18,630 $
5,674
1,114
25,418 $
17,571
6,088
607
24,266
$
$
During the years ended December 31, 2020, 2019 and 2018, in accordance with ASC 350-40, Internal Use Software, we
capitalized $488, $596, and $6,191, respectively, of certain internal use software development costs. Software
development 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, 2020, 2019 and 2018, we amortized internal use software development costs of $725, $699,
and $0, respectively. Amortization for these internal use software development costs are expected to be approximately
$786 per year.
17
7. ACCRUED EXPENSES
Accrued expenses as of December 31, 2020 and 2019 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
2020
2019
$
1,271 $
7,462
5,070
8,062
5,030
896
5,281
$
33,072 $
6,156
6,898
5,654
7,143
4,801
3,255
4,054
37,961
Long-term debt as of December 31, 2020 and 2019 consisted of the following:
Ciner Wyoming Equipment Financing Arrangement with maturity date of March 26, 2028,
fixed interest rate of 2.479%
$
27,552 $
—
Ciner Wyoming Credit Facility, unsecured principal expiring on August 1, 2022, variable
interest rate as a weighted average rate of 2.25% and 3.27% at December 31, 2020 and
December 31, 2019, respectively
Total debt
Less current portion of long-term debt
Total long-term debt
102,500
130,052
2,983
127,069 $
129,500
129,500
—
129,500
$
2020
2019
Aggregate maturities required on long-term debt at December 31, 2020 are due in future years as follows:
2021
2022
2023
2024
2025
Thereafter
Total
$
$
3,031
105,607
3,185
3,265
3,347
11,840
130,275
Ciner Wyoming Equipment Financing Arrangement
On March 26, 2020, Ciner Wyoming and Banc of America Leasing & Capital, LLC, as lender (the “Equipment Financing
Lender”), entered into an equipment financing arrangement (the “Ciner Wyoming Equipment Financing Arrangement”)
including a Master Loan and Security Agreement, dated as of March 25, 2020 (as amended, the “Master Agreement”) and
an Equipment Security Note Number 001, dated as of March 25, 2020 (the “Initial Secured Note”), which provides the
terms and conditions for the debt financing of certain equipment related to Ciner Wyoming’s new natural gas-fired turbine
co-generation facility that became operational in March 2020. Each equipment financing under the Ciner Wyoming
Equipment Financing Arrangement will be evidenced by the execution of one or more equipment notes (including the
Initial Secured Note) that incorporate the terms and conditions of the Master Agreement (each, an “Equipment Note”). In
order to secure the payment and performance of Ciner Wyoming’s obligations under the Ciner Wyoming Equipment
Financing Arrangement and other debt obligations owed by Ciner Wyoming to the Equipment Financing Lender, Ciner
Wyoming granted to the Equipment Financing Lender a continuing security interest in all of Ciner Wyoming’s right, title
and interest in and to the Equipment (as defined in the Master Agreement) and certain related collateral.
The Ciner Wyoming Equipment Financing Arrangement (1) incorporates all covenants in the Ciner Wyoming Credit
Facility (as defined below), now or hereinafter existing, or in any applicable replacement credit facility accepted in
18
writing by the Equipment Financing Lender, that are based upon a specified level or ratio relating to assets, liabilities,
indebtedness, rentals, net worth, cash flow, earnings, profitability, or any other accounting-based measurement or test, and
(2) includes customary events of default subject to applicable grace periods, including, among others, (i) payment
defaults, (ii) certain mergers or changes in control of Ciner Wyoming, (iii) cross defaults with certain other indebtedness
(a) to which the Equipment Financing Lender is a party or (b) to third parties in excess of $10 million, and (iv) the
commencement of certain insolvency proceedings or related events identified in the Master Agreement. Upon the
occurrence of an event of default, in its discretion, the Equipment Financing Lender may exercise certain remedies,
including, among others, the ability to accelerate the maturity of any Equipment Note such that all amounts thereunder
will become immediately due and payable, to take possession of the Equipment identified in any Equipment Note, and to
charge Ciner Wyoming a default rate of interest on all then outstanding or thereafter incurred obligations under the Ciner
Wyoming Equipment Financing Arrangement.
Among other things, the Initial Secured Note:
•
•
has a principal amount of $30,000,000;
has a maturity date of March 26, 2028;
shall be payable by Ciner Wyoming to the Equipment Financing Lender in 96 consecutive monthly installments
•
of principal and interest commencing on April 26, 2020 and continuing thereafter until the maturity date of the Initial
Secured Note, which shall be in the amount of approximately $307,000 for the first 95 monthly installments and
approximately $4,307,000 for the final monthly installment; and
entitles Ciner Wyoming to prepay all (but not less than all) of the outstanding principal balance of the Initial
•
Secured Note (together with all accrued interest and other charges and amounts owed thereunder) at any time after one (1)
year from the date of the Initial Secured Note, subject to Ciner Wyoming paying to the Equipment Financing Lender an
additional prepayment amount determined by the amount of principal balance prepaid and the date such prepayment is
made.
In connection with the Second Ciner Wyoming Amendment (as defined below), the Master Agreement was amended to
incorporate, among other things, the modified covenants set forth in the Second Ciner Wyoming Amendment related to
consolidated leverage ratios of Ciner Wyoming.
Ciner Wyoming’s balance under the Ciner Wyoming Equipment Financing Arrangement at December 31, 2020 was $27.8
million ($27.6 million net of financing costs).
At December 31, 2020, Ciner Wyoming was in compliance with all financial covenants of the Ciner Wyoming Equipment
Financing Arrangement. In connection with the event of default (the “Facilities Agreement Default”) under the Facilities
Agreement that arose in February 2021 (as defined and described below in the WE Soda and Ciner Enterprises Facilities
Agreement section), Ciner Wyoming entered into a second amendment to the Master Agreement (the “Second
Amendment to the Master Agreement”) on March 5, 2021. Such amendment modified the definition of change of control
under the Master Agreement in order to prevent an event of default thereunder that could have otherwise resulted from the
Facilities Agreement lenders foreclosing on certain equity interests in Ciner Holdings (the “Equity Default Remedy”) as a
remedy for the Facilities Agreement Default, or as a remedy for future events of default under the Facilities Agreement, as
amended. Management is not aware of any current circumstances that would result in an event of default under the Ciner
Wyoming Equipment Financing Arrangement in the next twelve months.
Ciner Wyoming Credit Facility
On August 1, 2017, Ciner Wyoming entered into a Credit Agreement (as amended, the “Ciner Wyoming Credit Facility”
and together with the Ciner Wyoming Equipment Financing Arrangement, the “Ciner Wyoming Debt Agreements”) with
each of the lenders listed on the respective signature pages thereof and PNC Bank, National Association (“PNC Bank”),
as administrative agent, swing line lender and a Letter of Credit (“L/C”) issuer. The Ciner Wyoming Credit Facility is a
19
$225.0 million senior 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 provides for revolving loans to fund working
capital requirements, and 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 $75.0 million, 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 $20.0 million for same-day swing
line advances and a sublimit up to $40.0 million for letters of credit.
On February 28, 2020, the Ciner Wyoming Credit Facility was amended to, among other things, increase flexibility for
debt financing to be incurred by Ciner Wyoming in connection with its new natural gas-fired turbine co-generation facility
by, among other things (i) increasing the basket for purchase money indebtedness permitted from $5.0 million to $30.0
million; (ii) adding procedures for transition to a benchmark other than the Eurodollar Rate to determine the applicable
interest rate (including reference to the Secured Overnight Financing Rate published by the Federal Reserve Bank of New
York), with provisions applying to that alternate benchmark; and (iii) adding customary new provisions relating to
qualified financial contracts, sanctions and anti-money laundering rules and laws.
On July 27, 2020, the Ciner Wyoming Credit Facility was further amended (the “Second Ciner Wyoming Amendment”)
to increase Ciner Wyoming’s financial and liquidity flexibility due to COVID-19. The Second Ciner Wyoming
Amendment, among other things, (i) increased, for a limited period, certain restrictive debt covenants that require Ciner
Wyoming and its subsidiaries to maintain certain leverage ratios and interest coverage ratios at the end of each period, (ii)
provided a tiered interest rate structure based on applicable covenant ratios and established a 0.5% interest floor, (iii)
effectuated changes to collateral restricted disbursements and covenanted to give security if covenant ratios are equal to or
above certain levels. The Second Ciner Wyoming Amendment also provided for covenants to restrict certain payments
and to give security in certain personal property of Ciner Wyoming following a fiscal quarter in which the leverage ratio
is equal to or higher than 3.50:1.0, so long as the applicable leverage ratio limit is otherwise adhered to. Any such security
would be released upon achievement of a leverage ratio less than 2.00:1.0 at the end of any quarter.
In addition, 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 Second Ciner Wyoming Amendment also required quarterly maintenance of a leverage ratio below those shown in
the table below and an interest coverage ratio of not less than 3.00:1.0.
20
Fiscal Quarter ending
December 31, 2020
March 31, 2021
June 30, 2021 (1)
September 30, 2021 (1)
December 31, 2021 and each fiscal quarter ending thereafter
Leverage Ratio
4.50:1.0
4.50:1.0
4.00:1.0
3.50:1.0
3.00:1.0
(1) See discussion of Third Amendment below which changed this requirement to 3:00:1:00.
The Second Ciner Wyoming Amendment added additional restrictions to (i) certain restricted payments (which includes
cash dividends, distributions and other restricted payments) by requiring the leverage ratio, both before and after giving
effect to such restricted payment, to be less than 2.50:1.0 (previously 3.00:1.0), (ii) permitted acquisitions by requiring
that the leverage ratio, both before and after giving effect to a permitted acquisition, be less than 2.50:1.0, and (iii) liens
by restricting the grant of any lien on any mineral right or mineral reserve, subject to certain exceptions. Once any
restricted payment (other than a permitted tax distribution) or permitted acquisition is consummated by Ciner Wyoming,
or one of its subsidiaries, the leverage ratio will reset to a maximum of 3.00:1.0. The Second Ciner Wyoming Amendment
also added a covenant that states if the leverage ratio thereunder is: (i) below 3.50:1.0 as of the end of any fiscal quarter,
any borrowings under the Ciner Wyoming Credit Agreement will be unsecured; or (ii) greater than or equal to 3.50:1.0 as
of the end of any fiscal quarter, any borrowings under the Ciner Wyoming Credit Agreement will be secured by
substantially all of Ciner Wyoming’s personal property, subject to certain customary exceptions, provided, that any such
security shall be released upon achievement of a leverage ratio less than 2.00:1.0 at the end of any fiscal quarter. Prior to
the Second Ciner Wyoming Amendment, a leverage ratio in excess of 3.00:1.0 for a quarterly period would have
constituted an event of default, whereas following effectiveness of the Second Ciner Wyoming Amendment, for each
quarterly period where the leverage ratio is permitted to be in excess of 3.50:1.0, a leverage ratio in excess of 3.50:1.0 for
such quarterly period would not by itself constitute an event of default so long as the applicable leverage ratio limit is
otherwise adhered to, but would permit the administrative agent and lenders under the Ciner Wyoming Credit Facility to
obtain a lien on certain personal property of Ciner Wyoming.
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.
a Base Rate, which equals the highest of (i) the federal funds rate in effect on such day plus 0.50%, (ii) the
Loans under the Ciner Wyoming Credit Facility bear interest at Ciner Wyoming’s option at either:
•
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
21
•
the Eurodollar Rate plus an applicable margin; provided, that with respect to an applicable loan, if the Eurodollar
Rate has ceased or will cease to be provided, if the regulatory supervisor for the administrator of the Eurodollar Rate or a
governmental authority having jurisdiction over the administrative agent determine that the Eurodollar Rate is no longer
representative or if the administrative agent determines that similar U.S. dollar-denominated credit facilities are being
executed or modified to incorporate or adopt a new benchmark interest rate to replace the Eurodollar Rate, the
administrative agent and Ciner Wyoming may establish an alternative interest rate for the applicable loan.
The Ciner Wyoming Credit Facility has an interest rate floor of 0.50%.
The unused portion of the Ciner Wyoming Credit Facility is subject to a per annum commitment fee and the applicable
margin of the interest rate under the Ciner Wyoming Credit Facility will be determined as follows:
Pricing
Tier
1
2
3
4
5
6
7
Leverage Ratio
< 1.25:1.0
≥ 1.25:1.0 but < 1.75:1.0
≥ 1.75:1.0 but < 2.25:1.0
≥ 2.25:1.0 but < 3.00:1.0
≥ 3.00:1.0 but < 3.50:1.0
≥ 3.50:1.0 but < 4.00:1.0
≥ 4.00:1.0
Eurodollar Rate
Loans
Base Rate
Loans
Commitment
Fee
1.500%
1.750%
2.000%
2.250%
2.500%
2.750%
3.000%
0.500%
0.750%
1.000%
1.250%
1.500%
1.750%
2.000%
0.250%
0.275%
0.300%
0.375%
0.375%
0.425%
0.475%
At December 31, 2020, Ciner Wyoming was in compliance with all financial covenants of the Ciner Wyoming Credit
Facility. In connection with the Facilities Agreement Default, Ciner Wyoming entered into a Third Amendment to the
Ciner Wyoming Credit Facility (the “Third Amendment”) in order to prevent an event of default thereunder that could
have otherwise resulted from the Facilities Agreement lenders exercising the Equity Default Remedy as a remedy for the
Facilities Agreement Default, or a future event of default under the Facilities Agreement, as amended. Such amendment
(i) modified the definition of change of control to exclude any change in control that could arise from lender actions under
the Facilities Agreement relating to any events of default under the Facilities Agreement; (ii) reduced the leverage ratio to
3:00 to 1.00 for the quarter ended June 30, 2021 and each fiscal quarter thereafter; and (iii) added a covenant that any
borrowings under the Wyoming Credit Facility are secured by substantially all of Ciner Wyoming’s personal property,
subject to certain exclusions. Management is not aware of any current circumstances that would result in an event of
default under the Ciner Wyoming Credit Facility in the next twelve months.
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, WE Soda Kimya Yatırımları Anonim Şirketi, Ciner Kimya Yatırımları Sanayi ve Ticaret Anonim
Şirketi, 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 include 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 certain transactions (including loans) with our affiliates, including such transactions that could reasonably be
expected to materially and adversely affect the interests of certain finance parties, (ii) restrict the ability to amend our
limited partnership agreement or the general partner’s limited liability company agreement or our other constituency
22
documents if such amendment could reasonably be expected to materially and adversely affect the interests of the lenders
to the Facilities Agreement, (iii) restrict the amount of our capital expenditures if certain ratios are not achieved by the
Ciner Obligors thereunder and (iv) prevent actions that enable certain restrictions or prohibitions on our ability to
upstream cash (including via distributions) to the borrowers under the Facilities Agreement. Based on the Ciner Obligors'
applicable ratios at December 31, 2020 the Partnership's expansion capital expenditures are prohibited until the Ciner
Obligors’ applicable ratios are at specified levels pursuant to 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,
which controls the general partner of the Partnership, if any of the borrowers or guarantors under the Facilities Agreement
are unable to satisfy its respective obligations under the Facilities Agreement.
Ciner Wyoming was informed that the Ciner Obligors were in compliance with the Facilities Agreement, as amended, as
of December 31, 2020.
In February 2021, Ciner Wyoming was informed that an event of default under the Facilities Agreement arose and that the
Ciner Obligors are currently working with the Facilities Agreement lenders to resolve this Facilities Agreement Default.
Absent resolution, the Facilities Agreement lenders have the right to foreclose on the equity interest in Ciner Holdings. In
order to prevent an event of default under each of the Ciner Wyoming Debt Agreements, which could have otherwise
resulted from the Facilities Agreement lenders exercising their Equity Default Remedy, Ciner Wyoming entered into the
Second Amendment to the Master Agreement and the Third Amendment to the Ciner Wyoming Credit Facility to modify
the related definitions of change of control as described above.
9. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities as of December 31, 2020 and 2019 consisted of the following:
Reclamation reserve
Derivative instruments and hedges, fair value liabilities and other
Total
Details of the reclamation reserve shown above are as follows:
Reclamation reserve at beginning of year
Accretion expense
Reclamation adjustment (1)
Reclamation reserve at end of year
2020
2019
7,337 $
1,370
8,707 $
5,672
2,915
8,587
2020
2019
5,672 $
322
1,343
7,337 $
5,366
306
—
5,672
$
$
$
$
(1) The reclamation costs are periodically evaluated for adjustments by the Wyoming Department of Environmental
Quality. See Note 12 “Commitments and Contingencies,” “Off-Balance Sheet Arrangements” for additional information
on our reclamation reserve, including recent changes to the underlying reclamation obligation that has resulted in the asset
retirement obligation reclamation adjustment.
23
10. EMPLOYEE BENEFIT PLANS
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 $55,157 and $54,800 at December 31, 2020 and December 31, 2019, 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 $(1,260), $994, and
$412 for the years ended December 31, 2020, 2019 and 2018, respectively. The decrease in pension costs in 2020 was
driven by better than expected return on assets and lower interest expense assumptions.
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, 2020, 2019 and 2018 were $3,366, $3,032, and
$2,833, 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 $13,128 and $13,757 at December 31, 2020 and 2019,
respectively.
The Company's allocated portion of postretirement cost (benefit) was $1,233, $(2,152), and $(2,940) for the years ended
December 31, 2020, 2019 and 2018, respectively. The postretirement benefits for the Company in 2019 and 2018 are due
to Ciner Corp amending its postretirement benefit plan in prior years.
24
11. ACCUMULATED OTHER COMPREHENSIVE INCOME AND LOSS
Accumulated other comprehensive loss as of December 31, 2020, 2019 and 2018 consisted of the following:
BALANCE at December 31, 2017
Interest Rate
Swap
Contract
Natural Gas
Forwards
Contracts
Total
$
(2) $
(7,207) $
(7,209)
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive loss
(354)
37
(1,002)
1,037
(1,356)
1,074
Net current-period other comprehensive income/(loss)
(317)
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
1,085
1,063
(536)
2,148
374
1,238
1,612
BALANCE at December 31, 2019
$
(855) $
(5,024) $
(5,879)
Other comprehensive (loss)/income before reclassification
Amounts reclassified from accumulated other comprehensive loss
(1,253)
835
3,762
2,607
Net current-period other comprehensive (loss)/income
(418)
6,369
2,509
3,442
5,951
BALANCE at December 31, 2020
$
(1,273) $
1,345 $
72
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:
2020
2019
2018
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
$
$
835 $
2,607
3,442 $
175 $
1,063
1,238 $
37
Interest expense
1,037 Cost of products sold
1,074
12. COMMITMENTS AND CONTINGENCIES
Lease and License Commitments
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.
25
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 that Watco holds an easement from Sweetwater Surface LLC. The land lease is renewable every
five years for a total period of thirty years, while the Sweetwater Surface LLC easement is perpetual. The Company has an
option agreement with Watco to assign the lease and easement to the Company at any time during the land lease term. An
immaterial annual rental is paid under the easement and lease.
As of December 31, 2020, the total minimum contractual rental commitments under the Company’s various operating
leases, including renewal periods is approximately $1,533 with the amount due in any of the next five years being
immaterial.
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 obligation related to these rail car leases are $9,687 in 2021, $6,737 in 2022, $3,395 in 2023, $2,255 in 2024,
$1,954 in 2025 and $2,084 thereafter. Total lease expense allocated to the Company from Ciner Corp was approximately
$11,304, $11,770 and $13,919 for the years ended December 31, 2020, 2019 and 2018, respectively, and is recorded in
freight costs.
Purchase Commitments - We have financial natural gas supply contracts to mitigate volatility in the price of natural gas.
As of December 31, 2020, these contracts totaled approximately $25,908 for the purchase of a portion of our natural gas
requirements over approximately the next four years. The supply purchase agreements have specific commitments of
$14,513 in 2021, $6,213 in 2022, $4,317 in 2023, and $864 in 2024. We have a separate contract that expires in 2021 and
renews annually thereafter, for transportation of natural gas with an average annual cost of approximately $4,046 per year.
In connection with the ANSAC exit we have an agreement for minimum logistics services in 2021. This arrangement
includes bilateral take or pay terms.
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
such legal proceedings we may be involved in from time to time 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 any such 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 Rock Springs
Royalty Company, LLC ("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 and predecessor in interest
to Sweetwater, to mine sodium minerals from certain 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) concurrently amended selected sections of the License land-lease including among other things, (a) extension of the
26
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 historically been subject to a self-bond agreement (the “Self-Bond
Agreement”) with the Wyoming Department of Environmental Quality (“WDEQ”) under which we committed to pay
directly for reclamation costs. The amount of the self-bond was $36,200 as of December 31, 2019. In May 2019, the State
of Wyoming enacted legislation that limits our and other mine operators’ ability to self-bond and required us to seek other
acceptable financial instruments to provide alternate assurances for our reclamation obligations by November 2020. We
provided such alternate assurances by timely securing a third-party surety bond effective October 15, 2020 (the “Surety
Bond”) for the then-applicable full self-bond amount $36,200, which was also the amount of our obligation as of
December 31, 2020. After we secured the Surety Bond, the previous Self-Bond Agreement was terminated. As of the date
of this Report, the impact on our net income and liquidity due to securing the Surety Bond has been immaterial and we
anticipate that to continue to be the case. The amount of such assurances that we are required to provide is subject to
change upon periodic re-evaluation by the WDEQ’s Land Quality Division. As a result of the most recent such periodic
re-evaluation, the Surety Bond amount was increased to $41,814 effective March 1, 2021.
13. AFFILIATE TRANSACTIONS
Agreements and transactions with affiliates have a significant impact on the Company’s financial statements because the
Company is a subsidiary in a global group structure. Agreements directly between the Company and other affiliates, or
indirectly between affiliates that the Company does not control, can have a significant impact on recorded amounts or
disclosures in the Company's financial statements, including any commitments and contingencies between the Company
and affiliates, or potentially, third parties.
Ciner Corp is the exclusive sales agent for the Company and through its membership in ANSAC, through December 31,
2020, Ciner Corp has responsibility for promoting and increasing the use and sale of soda ash and other refined or
processed sodium products produced. Through December 31, 2020, ANSAC served as the primary international
distribution channel for the Partnership and two other U.S. manufacturers of trona-based soda ash. ANSAC operated on a
cooperative service-at-cost basis to its members such that typically any annual profit or loss is passed through to the
members. As previously disclosed, the Partnership was informed on November 9, 2018 that Ciner Corp, an affiliate of the
Company, had as part of its strategic initiative to gain better direct access and control of international customers and
logistics and the ability to leverage the expertise of Ciner Group, the world’s largest natural soda ash producer, delivered a
notice to terminate its membership in ANSAC. Such termination was expected to be effective as of the end of day on
December 31, 2021. On July 27, 2020, ANSAC and the members thereof entered into an agreement, effective as of July
24, 2020, that, among other things, terminated Ciner Corp’s membership in ANSAC effective as of December 31, 2020
(the “ANSAC termination date”), a year earlier than previously announced (the “ANSAC Early Exit Agreement”).
Effective as of the end of day on December 31, 2020 Ciner Corp exited ANSAC.
In connection with the settlement agreement with ANSAC, there are sales commitments to ANSAC in 2021 and 2022
where Ciner Corp will continue to sell, at substantially lower volumes, product to ANSAC for export sales purposes, with
a fixed rate per ton selling, general and administrative expense, and will also purchase a limited amount of export logistics
services in 2021. Through in part the Company’s affiliates, the Company has amongst other things: (i) obtained its own
international customer sales arrangements for 2021, (ii) obtained third-party export port services, and (iii) chartered and
executed its own international product delivery.
27
Historically, by design and prior to Ciner Corp’s exit from ANSAC, ANSAC managed most of our international sales,
marketing and logistics, and as a result, was our largest customer for the years ended December 31, 2020, 2019 and 2018,
accounting for 45.4%, 60.4% and 52.0%, respectively, of our net sales. Although ANSAC was our largest customer for
the aforementioned periods, we anticipate that the impact of Ciner Corp’s exit from ANSAC on our net sales, net income
and liquidity will be limited. We made this determination primarily based upon the belief that we will continue to be one
of the lowest cost producers of soda ash in the global market. With a low-cost position combined with better direct access
and control of our customers and logistics and the ability to leverage Ciner Group’s expertise in these areas, we believe
we will be able to adequately replace these net ANSAC sales. As of January 1, 2021, Ciner Corp began managing the
Partnership's sales and marketing efforts for exports with the ANSAC exit being complete. Ciner Corp is leveraging the
distributor network established by Ciner Group while independently reviewing current and potential distribution partners
to optimize our reach into each market.
Post-ANSAC International Export Capabilities
In accordance with the ANSAC Early Exit Agreement, Ciner Corp has begun marketing soda ash on our behalf directly
into international markets and building its international sales, marketing and supply chain infrastructure. We now have
access to utilize the distribution network that has already been established by the global Ciner Group. We believe that by
having the option of combining our volumes with Ciner Group’s soda ash exports from Turkey, Ciner Corp’s strategic
exit from ANSAC has allowed us to leverage global Ciner Group’s, the world’s largest natural soda ash producer, soda
ash operations which we expect will improve our ability to optimize our market share both domestically and
internationally. Being able to work with the global Ciner Group provides us with the opportunity to better attract and more
efficiently serve larger global customers. In addition, the Company is working to enhance its international logistics
infrastructure that includes, among other things, a domestic port for export capabilities. These export capabilities are being
developed by an affiliated company and options being evaluated range from continued outsourcing in the near term to
developing its own port capabilities in the longer term.
Selling, general and administrative expenses also include amounts charged to the Company by its affiliates principally
consisting of salaries, benefits, office supplies, professional fees, travel, rent and other costs of certain assets used by the
Company. On October 23, 2015, the Company entered into a Services Agreement (the “Services Agreement”) with our
general partner and Ciner Corp. Pursuant to the Services Agreement, 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 governing Ciner
Wyoming, Ciner Wyoming reimburses us for employees who operate our assets and for support provided to Ciner
Wyoming. These transactions do not necessarily represent arm's length transactions and may not represent all costs if
Ciner Wyoming operated on a standalone basis.
The total selling, general and administrative costs charged to the Company by affiliates for the years ended December 31,
2020, 2019, and 2018 were as follows:
Ciner Corp
ANSAC (1)
Ciner Resources
Total selling, general and administrative expenses - affiliates
2020
2019
2018
$
$
15,659 $
1,362
377
17,398 $
14,233 $
3,508
663
18,404 $
13,728
2,998
972
17,698
(1) ANSAC allocates its expenses to its members using a pro rata calculation based on sales.
28
Net sales to affiliates for the years ended December 31, 2020, 2019 and 2018 were as follows:
ANSAC
Total
2020
177,891 $
177,891 $
2019
315,847 $
315,847 $
2018
253,345
253,345
$
$
As of December 31, 2020 and 2019, the Company had due from/to with affiliates as follows:
ANSAC
Ciner Corp
Other
Total
2020
2019
Due from
Affiliates
Due to
Affiliates
Due from
Affiliates
Due to
Affiliates
$
$
41,948 $
44,594
155
86,697 $
183 $
2,520
162
2,865 $
53,859 $
35,713
5,543
95,115 $
1,614
1,423
178
3,215
The increase in due from Ciner Corp from December 31, 2019 to December 31, 2020 is due to timing of funding of
pension and postretirement plans offered and administered by Ciner Corp.
14. 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,
2020, 2019 and 2018 were as follows:
Domestic
International
Total net sales
15. SUBSEQUENT EVENTS
2020
208,838 $
183,393
392,231 $
2019
206,996 $
315,847
522,843 $
2018
233,414
253,345
486,759
$
$
In an effort to achieve greater financial and liquidity flexibility during the COVID-19 pandemic, (i) effective February 22,
2021, the board of directors of the general partner of the Company unanimously approved a continuation of the
suspension of quarterly distributions to the unitholders of the Company for the quarter ended December 31, 2020, and (ii)
effective February 22, 2021, the board of managers of Ciner Wyoming unanimously approved a continuation of the
suspension of quarterly distributions to the members of Ciner Wyoming for the quarter ended December 31, 2020 in a
continued effort to achieve greater financial and liquidity flexibility during the COVID-19 pandemic. In March 2021, the
board of managers of Ciner Wyoming approved a special $8.0 million distribution, to amongst other things, provide the
Partnership with funds to retire its Ciner Resources Credit Facility.
In connection with the Facilities Agreement Default (as defined and described in Note 9 “Debt” in the Ciner Wyoming
Equipment Financing Arrangement section), effective March 5, 2021 the Ciner Wyoming Equipment Financing
Arrangement and the Ciner Wyoming Credit Facility were amended respectively in order to amongst other things,
carveout from the definition of Change of Control any change in control that could arise from lender actions under the
Facilities Agreement relating to any events of default under the Facilities Agreement, see Note 8, “Debt” for additional
information.
******
29
Unitholder Information
Partnership Headquarters
Website
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, Suite 2400
Houston, TX 77001-2007
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
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 allocated 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.
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