Natural Resource Partners L.P.
1201 Louisiana Street, 34th Floor
Houston, Texas 77002
www.nrplp.com
2018 Annual Report
Natural Resource Partners L.P.
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2018 Financial Highlights
Unitholder Information
(in thousands, except per unit)
2018 (1) (2)
2017 (2)
2016 (2)
2015 (2)
2014 (2)
Total revenues and other income
$ 278,512
$ 246,325
$ 279,244
$ 300,635
$ 308,867
For the Years Ended December 31
Asset impairments
Income (loss) from operations
Net income (loss) from continuing operations
Net income from continuing operations
excluding impairments
Net income (loss) from discontinued operations
Net income (loss)
Per common unit amounts (basic)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Per common unit amounts (diluted)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Distributions paid per common unit
Average number of common
units outstanding - basic
Average number of common
units outstanding - diluted
Net cash provided by (used in)
$
18,280
$ 192,538
$ 122,360
$ 140,640
$
17,687
$ 140,047
$
$
$
$
$
$
$
7.35
1.42
8.77
5.90
0.86
6.76
1.80
12,244
20,234
Operating activities of continuing operations
$ 178,282
Investing activities of continuing operations
Financing activities of continuing operations
$
$
7,607
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,967
176,559
82,485
85,452
6,182
88,667
4.57
0.50
5.06
3.68
0.28
3.96
1.80
12,232
21,950
$
$
$
$
$
$
$
$
$
$
$
$
$
15,861
181,157
$
378,327
$ (170,699)
90,626
$ (260,443)
106,487
$ $117,884
6,266
$ (311,277)
96,892
$ (571,720)
7.28
0.50
7.78
7.28
0.50
7.78
1.80
12,232
12,232
$
$
$
$
$
$
$
(20.80)
(24.94)
(45.75)
(20.80)
(24.94)
(45.75)
2.70
12,232
12,232
$
$
$
$
$
$
$
$
$
$
$
$
$
26,209
176,108
96,681
122,890
12,149
108,830
8.37
1.05
9.42
8.37
1.05
9.42
14.00
11,326
11,326
112,151
9,807
$
$
80,243
65,057
$
$
144,907
15,805
$
$
189,418
1,566
(6,839)
$ (134,149)
$ (146,373)
$ (166,443)
$ (237,314)
Free cash flow (3)
Distributable cash flow (3)
Adjusted EBITDA (3)
Cash and cash equivalents
Total assets
$ 183,440
$ 383,980
$ 230,241
$ 206,030
$
$
$
$
121,324
121,958
211,483
$
$
75,970
255,172
$
$
144,210
157,815
$
$
193,665
195,045
$ 235,273
$ 240,553
$ 260,447
26,980
$
39,171
$
40,244
$
45,975
$ 1,341,647
$ 1,389,164
$ 1,448,649
$ 1,674,865
$ 2,431,549
Current portion of long-term debt, net
$
115,184
$
79,740
$
140,037
$
80,745
$
80,745
Long-term deb, net
$ 557,574
$ 729,608
$ 990,234
$ 1,130,696
$ 1,190,558
Class A Convertible Preferred Units
Partners’ capital
$ 164,587
$ 423,481
$
$
173,431
265,211
$
$
—
151,530
$
$
—
76,336
$
$
—
720,155
(1) On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, and all the related amendments (the “new revenue standard”
and “ASC 606”) to all open contracts using the modified retrospective method. NRP recognized a $70.5 million cumulative effect of adoption adjustment in the opening balance of
partners’ capital on January 1, 2018. Comparative information has not been restated and continues to be reported under the standards in effect for those periods. Refer to “Item 8. Financial
Statements and Supplementary Schedules—Note 2. Summary of Significant Accounting Policies” and “Item 8. Financial Statements and Supplementary Schedules—Note 3. Revenue from
Contracts with Customers” in this Annual Report on Form 10-K for more information.
(2) In December 2018, we sold our construction aggregates materials business and have classified the assets and liabilities, operating results and cash flows of the construction aggre-
gates business as discontinued operations for all periods presented. Refer to “Item 8. Financial Statements and Supplementary Schedules—Note 4. Discontinued Operations” in this Annual
Report on Form 10-K for more information.
(3) See “—Non-GAAP Financial Measures” in this Annual Report on Form 10-K form more information.
Partnership Headquarters
Website
www.nrplp.com
1201 Louisiana Street
Suite 3400
Houston, TX 77002
713-751-7507
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,
Regional Offices
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
Natural Resource Partners L.P.
Tax Package Support
P.O. Box 799060
Dallas, TX 75379-9060
Fax: 1-866-554-3842
Transfer Agent and Registrar
Toll Free: 1-888-334-7102
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.
Ernst & Young LLP
5 Houston Center
1401 McKinney, Suite 1200
Houston, TX 77001-2007
American Stock Transfer
and Trust Company
Client Operations
6201 15th Avenue
Brooklyn, NY 11219
Website: www.amstock.com
Email: info@amstock.com
800-937-5449
Independent Auditors
their Schedule K-1 to the following:
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
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
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. 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.
1
Natural Resource Partners L.P.
2018 Annual Report
To Our Unitholders
2018 was another transformative year for NRP. We saw continued stability
in the coal markets, resulting in steady free cash flow generation. We also
executed on key strategic initiatives, such as the sale of our construction
aggregates business in December, which enabled us to accelerate the
deleveraging of our balance sheet. We ended 2018 with strong liquidity,
$206 million of cash and $100 million of credit facility borrowing capacity.
2018 Accomplishments Include:
•
•
•
•
•
Sale of VantaCore for $205 million, representing our exit from
the construction aggregates business
Favorable litigation settlement resulting in 2018 cash of $25 million
Reduced debt by $141 million as of December 31, 2018 and
$190 million as of January 15, 2019
Lowered leverage (debt to EBITDA) from 2015 levels of 5.3x to 3.0x
Continued quarterly common unit distributions of $0.45 per unit
“We saw continued stability in the coal
markets, resulting in steady free cash
flow generation. We also executed on key
strategic initiatives, such as the sale of
our construction aggregates business in
December, which enabled us to accelerate
the deleveraging of our balance sheet.”
1
Natural Resource Partners L.P.
2018 Annual Report
Business Highlights
Our Coal Royalty segment produced 83% of the partnership’s Revenue
and other income and 82% of the partnership’s Free Cash Flow in 2018.
This is primarily a result of solid metallurgical and thermal coal markets
driven by strong export demand and steel industry fundamentals.
Our soda ash business, of which we own a 49% equity interest, continues
to perform and deliver cash distributions. We remain confident in Ciner
Wyoming’s ability to produce some of the best quality and lowest cost
natural soda ash over the long term.
Looking Forward
We remain committed to our goal of reducing debt, strengthening the
balance sheet and maximizing the intrinsic value of the partnership.
In April 2019, we extended the maturity date of our $100 million revolving
credit facility to 2023, and issued $300 million of 9.125% Senior Notes
due 2025. We used the proceeds from this offering, together with cash on
hand, to redeem all of our outstanding $346 million 10.500% Senior Notes
due 2022, thus reducing further our total debt by $46 million. Looking
ahead, we remain steadfast in our focus on de-levering and de-risking the
partnership as we view this as the best way to create long-term value for
our stakeholders. We thank you for your continued support of NRP and
we look forward to the opportunities ahead.
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
“We remain committed
to our goal of reducing
debt, strengthening
the balance sheet and
maximizing the intrinsic
value of the partnership.”
2
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2018 or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 1-31465
NATURAL RESOURCE PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
35-2164875
(I.R.S. Employer Identification Number)
1201 Louisiana Street, Suite 3400, Houston, Texas 77002
(Address of principal executive offices)
Registrant's telephone number, including area code (713) 751-7507
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Units representing limited partner interests
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 and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K.
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
(Do not check if a smaller reporting company)
Accelerated Filer
Smaller Reporting Company
Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes
No
The aggregate market value of the common units held by non-affiliates of the registrant on June 30, 2018, was $248 million based on a closing
price on that date of $31.40 per unit as reported on the New York Stock Exchange.
As of March 1, 2019, there were 12,261,199 common units outstanding.
Documents incorporated by reference: None.
Items 1. and 2. Business and Properties
TABLE OF CONTENTS
PART I
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
PART II
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Signatures
Financial Statements and Supplementary Data
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors and Executive Officers of the Managing General Partner and Corporate Governance
PART III
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Exhibits, Financial Statement Schedules
PART IV
1
24
38
39
39
40
40
44
65
67
119
119
121
122
129
138
140
147
150
154
i
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
Statements included in this 10-K may constitute forward-looking statements. In addition, we and our representatives may
from time to time make other oral or written statements which are also forward-looking statements. Such forward-looking statements
include, among other things, statements regarding: our business strategy; our liquidity and access to capital and financing sources;
our financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses
and results of operations; projected production levels by our lessees; Ciner Wyoming LLC’s ("Ciner Wyoming") trona mining and
soda ash refinery operations; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings
involving us, and of scheduled or potential regulatory or legal changes; and global and U.S. economic conditions.
These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations,
estimates, assumptions and beliefs concerning future events impacting us and involve a number of risks and uncertainties. We
caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or
implied in the forward-looking statements. You should not put undue reliance on any forward-looking statements. See "Item 1A.
Risk Factors" in this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our
actual financial condition to differ.
ii
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 10.50% Senior Notes due
2022 (the "2022 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, soda ash from trona and other natural resources.
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 in the Northern Powder River Basin in the United
States. Our aggregates and industrial minerals properties are located in a number of states across the United States. Our oil and
gas royalty assets are primarily located in Louisiana.
Soda Ash—consists of our 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining operation and soda
ash refinery, in the Green River Basin of Wyoming. Ciner Resources, LP, our operating partner, mines the trona, processes it into
soda ash and distributes the soda ash both domestically and internationally to the glass and chemicals industries.
In December 2018, we sold our construction aggregates business for $205 million, before customary purchase price
adjustments and transaction expenses, and recorded a gain of $13.1 million. Our exit from the construction aggregates business
enabled us to further reduce debt, focus on our Coal Royalty and Other and Soda Ash business segments and represented a strategic
shift as we exited the operations of our construction aggregates business.
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, L.P. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management
LP (collectively referred to as "GoldenTree"), Mr. Robertson, Jr. is entitled to appoint the members of the Board of Directors of
GP Natural Resource Partners LLC and has delegated the right to appoint one director to Blackstone.
The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited
Partnership or Quintana Minerals Corporation, which are companies controlled by Mr. Robertson, Jr. These officers allocate varying
percentages of their time to managing our operations. Neither our general partner, GP Natural Resource Partners LLC, nor any of
their affiliates receive any management fee or other compensation in connection with the management of our business, but they
are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.
We have regional offices through which we conduct our operations, the largest of which is located at 5260 Irwin Road,
Huntington, West Virginia 25705 and the telephone number is (304) 522-5757. Our principal executive office is located at 1201
Louisiana Street, Suite 3400, Houston, Texas 77002 and our telephone number is (713) 751-7507.
1
Segment and Geographic Information
The amount of 2018 revenue and other income from our two operating segments is shown below. For additional business
segment information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
—Results of Operations" and "Item 8. Financial Statements and Supplementary Data—Note 8. Segment Information" in this
Annual Report on Form 10-K, which are both incorporated herein by reference.
(In thousands)
Coal Royalty and Other
Soda Ash
Total
Coal Royalty and Other Segment
Amount
% of Total
$
$
230,206
48,306
278,512
83%
17%
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 that generate additional revenues generally based on throughput or
rents in the Illinois Basin. As described in the "—Other Coal Royalty and Other Segment Assets" section below, we also own oil
and gas, aggregates and industrial mineral reserves that generate a portion of 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. Lessees calculate royalty payments due
to us and are required to report tons of minerals removed as well as the sales prices of the extracted minerals. Therefore, to a great
extent, amounts reported as royalty revenue are based upon the reports of our lessees. We periodically audit this information by
examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify that the information
that our lessees have submitted to us is accurate. Our audit and inspection processes are designed to identify material variances
from lease terms as well as differences between the information reported to us and the actual results from each property.
In addition to their royalty obligations, our lessees are often subject to minimum payments, which reflect amounts we are
entitled to receive even if no mining activity occurs during the period. Minimum payments are usually credited against future
royalties that are earned as minerals are produced. In certain leases, the lessee is time limited on the period available for recouping
minimum payments and such time is unlimited on other leases.
Because we do not operate any coal mines, our coal royalty business does not bear ordinary operating costs and has limited
direct exposure to environmental, permitting and labor risks. Our lessees, as operators, are subject to environmental laws, permitting
requirements and other regulations adopted by various governmental authorities. In addition, the lessees generally bear all labor-
related risks, including retiree health care costs, black lung benefits and workers’ compensation costs associated with operating
the mines on our coal and aggregates properties. We pay property taxes on our properties, which are largely reimbursed by our
lessees pursuant to the terms of the various lease agreements.
2
Coal Reserves and Production Information
The following table presents coal reserves information as of December 31, 2018 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
366,633
723,795
59,317
1,149,745
302,002
—
—
1,451,747
2,934
238,531
19,966
261,431
5,074
166,590
1,957
435,052
369,567
962,326
79,283
1,411,176
307,076
166,590
1,957
1,886,799
(1)
In excess of 94% of the reserves presented in this table are currently leased to third parties.
The following table presents the type of coal reserves by major coal region as of December 31, 2018:
(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
308,054
541,625
58,957
908,636
307,076
166,590
1,875
61,513
420,701
20,326
502,540
—
—
82
369,567
962,326
79,283
1,411,176
307,076
166,590
1,957
1,384,177
502,622
1,886,799
(1) For purposes of this table, we have defined metallurgical coal reserves as reserves located in seams that historically have
been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the
metallurgical category can also be used as thermal coal.
3
The following table presents the sulfur content and the typical quality of our coal reserves by major coal region as of
December 31, 2018:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
Total Appalachia Basin
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total
Compliance
Coal (2)
Low
(<1.0%)
Sulfur Content
Typical Quality (1)
Medium
(1.0%
to
1.5%)
High
(>1.5%)
Total
Heat
Content
(Btu per
pound)
Sulfur
(%)
46,647
453,122
44,903
544,672
—
—
82
46,847
671,508
49,518
767,873
—
166,590
1,957
905
321,815
244,489
27,175
272,569
2,152
—
—
46,329
2,590
370,734
304,924
—
—
369,567
962,326
79,283
1,411,176
307,076
166,590
1,957
544,754
936,420
274,721
675,658
1,886,799
12,873
13,232
13,408
13,148
11,474
8,800
6,964
2.89
0.90
0.96
1.43
3.29
0.65
0.69
(1) Unless otherwise indicated, the coal quality information in this Annual Report and on the Form 10-K is reported on an as-
received basis with an assumed moisture of 6% for Appalachian 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.
Methodologies Used in Mineral Reserve Estimation
All of the reserves reported above are recoverable proven or probable reserves as determined by the SEC’s Industry Guide
7 and are estimated by our internal reserve geologist 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. 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."
4
The following table presents the type of coal production by major coal region for the year ended December 31, 2018:
(Tons in thousands)
Appalachia Basin
Northern
Central
Southern
Total Appalachia Basin
Illinois Basin
Northern Powder River Basin
Total
Major Coal Producing Properties
Type of Coal
Thermal
Metallurgical
Total
2,152
2,986
284
5,422
2,739
4,313
1,035
12,011
1,426
14,472
—
—
12,474
14,472
3,187
14,997
1,710
19,894
2,739
4,313
26,946
The following table provides a summary of our major coal royalty properties and is followed by additional information for
each property or lease name:
Region
Property/Lease Name
Operator
Coal Type
2018 Production
(Millions of Tons)
Appalachia Basin
Northern
Northern
Northern
Central
Central
Central
Central
Central
Central
Central
Central
Southern
Illinois Basin
Illinois Basin
Illinois Basin
Northern Powder
River Basin
Hibbs Run
Mettiki Coal
Carter Roag
Contura-CAPP (VA)
Blackjewel-Lynch
Coal Mountain
Aracoma
Pinnacle (1)
Kepler
Greenbrier Minerals
South Fork Coal
Oak Grove
Macoupin
Williamson
Hillsboro
Murray Energy Corporation
Thermal
Alliance Resource Partners
Met/Thermal
Metinvest
Contura Energy, Inc.
Blackjewel LLC
CM Energy Properties, LP and Ramaco
Resources, Inc.
Contura Energy, Inc.
Mission Coal, LLC (2)
Contura Energy, Inc.
Coronado Coal
Xinergy Corp.
Mission Coal, LLC (2)
Foresight Energy LP
Foresight Energy LP
Foresight Energy LP
Met
Met
Met/Thermal
Met/Thermal
Met/Thermal
Met
Met
Met
Met
Met
Thermal
Thermal
Thermal
Thermal
Western Energy
Westmoreland Coal Company (2)
1.5
1.1
0.4
3.3
2.3
2.2
1.7
1.1
0.5
0.4
0.2
1.4
2.0
0.4
—
4.3
(1) Pinnacle property is currently closed and not producing.
(2) Operator currently in bankruptcy.
5
Appalachia Basin—Northern Appalachia
Hibbs Run. The Hibbs Run property is located in Marion County, West Virginia. In 2018, approximately 1.5 million tons
were produced from this thermal property. We lease this property to a subsidiary of Murray Energy Corporation. Coal from this
property is produced from longwall mines and shipped by rail to utility customers. The royalty rate for this property is a low fixed
rate per ton and has a significant effect on the weighted average per ton revenue for the region.
Mettiki Coal. The Mettiki Coal property is located in Tucker and Grant Counties, West Virginia. In 2018, approximately
1.1 million tons metallurgical and thermal tons were produced from this property. We lease this property to a subsidiary of Alliance
Resource Partners. Production comes from this mine via a longwall operation. Coal is shipped by truck to a local utility customer
and by train to metallurgical customers. NRP pays an override royalty equal to the royalty received from Mettiki to Western
Pocahontas Properties Limited Partnership per the terms of the deed.
Carter Roag. The Carter Roag property is located in Randolph and Upshur Counties, West Virginia. In 2018, approximately
0.4 million tons were produced from this metallurgical coal property. We lease this property to a subsidiary of Metinvest. Production
comes from the Morgan Camp and Pleasant Hill room and pillar deep mines. The coal production is trucked to Carter Roag’s
preparation plant situated at Star Bridge, West Virginia. The coal produced from this property is shipped via the CSX railroad to
Baltimore and then by ocean vessel to Metinvest's steel mills in Ukraine.
6
The map below shows the location of our major properties in Northern Appalachia:
7
Appalachia Basin—Central Appalachia
Contura-CAPP (VA). The Contura-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties,
Virginia. In 2018, approximately 3.3 million tons were produced from this property, substantially all of which was metallurgical
coal. We lease this property to subsidiaries of Contura Energy, Inc ("Contura Energy"). Production that comes from underground
room and pillar and surface mines is trucked to one of two preparation plants. Coal is shipped via the CSX and Norfolk Southern
railroads to utility and metallurgical customers.
Blackjewel-Lynch. The Blackjewel-Lynch (previously referred to as Resource Development) property is located in Harlan
and Letcher Counties, Kentucky and Wise County, Virginia. In 2018, approximately 2.3 million tons of metallurgical and thermal
coal were produced from this property. We lease this property to Blackjewel, LLC. Production comes from underground room and
pillar and surface mines. This property has the ability to ship coal on the CSX and Norfolk Southern railroads to utility and
metallurgical customers.
Coal Mountain. The Coal Mountain property is located in Wyoming County, West Virginia. In 2018, approximately 2.2
million tons of metallurgical coal were produced from the property. We lease this property to CM Energy Properties, LP and
Ramaco Resources Inc. Metallurgical coal is produced from surface mining and metallurgical and thermal coal are produced from
underground room and pillar mines and trucked to preparation plants on the property. Coal is shipped via the Norfolk Southern
and CSX railroad to various utility customers and both domestic or export metallurgical customers.
Aracoma. The Aracoma property is located in Logan County, West Virginia. In November 2018, Alpha Natural Resources,
Inc. (the former controlling company of the property) merged into Contura Energy. This property is now leased to a subsidiary of
Contura Energy. Approximately 1.7 million tons of coal, substantially all of which is metallurgical coal, was produced in 2018
from the property. Coal is produced from underground room and pillar mines and transported by belt or truck to the preparation
plant on the property. Coal is shipped via the CSX railroad to utility customers and to various domestic and export metallurgical
customers.
Pinnacle. The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. In 2018, approximately
1.1 million tons of metallurgical coal was produced from our reserves on this property. We lease the property to a subsidiary of
Mission Coal, LLC ("Mission Coal"), which filed for bankruptcy protection in 2018. Production came from a longwall mine and
was transported by beltline to a preparation plant on the property. Coal was shipped via Norfolk Southern railroad to both domestic
and export customers. The Pinnacle mine is currently closed and the preparation plant is idled.
Kepler. The Kepler property is located in Wyoming County, West Virginia. In 2018, approximately 0.5 million tons were
produced from the property. We lease this property to a subsidiary of Contura Energy. In November 2018, Alpha Natural Resources,
Inc. (the former controlling company of the property) merged into Contura Energy. Metallurgical coal is produced from two
underground room and pillar mines that is transported by belt and truck to a preparation plant on the property. Coal is shipped via
the Norfolk Southern railroad to various metallurgical customers.
Greenbrier Minerals. The Greenbrier Minerals property is located in Greenbrier County, West Virginia. In 2018,
approximately 0.4 million tons were produced from the property. This property is leased to Coronado Coal. Metallurgical coal is
produced from surface mines and transported by truck to a preparation plant. Coal is shipped via the CSX railroad to various export
metallurgical customers.
South Fork Coal. The South Fork Coal property is located in Greenbrier County, West Virginia. In 2018, approximately
0.2 million tons were produced from the property. This property is leased to South Fork Coal Company, LLC, a subsidiary of
Xinergy Corp. Metallurgical coal is produced from surface mines and transported by truck to a preparation plant. Coal is shipped
via the CSX railroad to export metallurgical customers.
8
The map below shows the location of our major properties in Central Appalachia:
9
Appalachia Basin—Southern Appalachia
Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2018, approximately 1.4 million tons of
metallurgical coal were produced from this property. We lease the property to a subsidiary of Mission Coal. Mission Coal filed
for bankruptcy protection during 2018. Production comes from a longwall mine and is transported primarily by beltline to a
preparation plant. Metallurgical coal is then shipped via railroad and barge to both domestic and export customers.
The map below shows the location of our major property in Southern Appalachia:
10
Illinois Basin
Macoupin. The Macoupin property is located in Macoupin County, Illinois. The property is under lease to Macoupin Energy,
a subsidiary of Foresight Energy LP ("Foresight Energy"). In 2018, approximately 2.0 million tons of thermal coal were sold from
our property. Production is from an underground room and pillar mine. Coal is shipped via the Norfolk Southern or Union Pacific
railroads or by barge to domestic utility or export customers.
Williamson. The Williamson property is located in Franklin and Williamson Counties, Illinois. The property is under lease
to Williamson Energy, a subsidiary of Foresight Energy. In 2018, approximately 0.4 million tons of thermal coal were sold from
our property. Production comes from a longwall mine. Coal is shipped primarily via the Canadian National railroad to domestic
utility customers. Approximately 6.1 million tons of additional production was received in 2018 in the form of override royalty
from an adverse property.
Hillsboro. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. The property is under lease to
Hillsboro Energy, a subsidiary of Foresight Energy. It had been idled since March 2015 until longwall panel development production
resumed in January 2019. When fully active, production at the mine has historically come from longwall mining methods. Coal
is shipped by rail via either the Union Pacific, Norfolk Southern or Canadian National railroads, or by barges to domestic utilities
or export customers.
In addition to these properties, we own loadout and other transportation assets at the Williamson and Macoupin mines and
at the Sugar Camp mines, which is also operated by Foresight Energy. See "—Coal Transportation and Processing Assets" below
for additional information on these assets.
11
The map below shows the location of our major properties in the Illinois Basin:
12
Northern Powder River Basin
Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2018,
approximately 4.3 million tons were produced from our property by a subsidiary of Westmoreland Coal Company. Coal is produced
by surface dragline mining methods, and the coal is transported by either truck or beltline to the Colstrip generation station located
at the mine mouth. Westmoreland Coal Company filed for bankruptcy protection during 2018.
The map below shows the location of our property in the Northern Powder River Basin:
13
Coal Transportation and Processing Assets
We own transportation and processing infrastructure related to certain of our coal properties, including loadout and other
transportation assets at Foresight Energy's Williamson and Macoupin mines in the Illinois Basin, for which we collect throughput
fees or rents. We lease our Macoupin and Williamson transportation and processing infrastructure to subsidiaries of Foresight
Energy and are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we
subcontract to a subsidiary of Foresight Energy. In addition, we own rail loadout and associated infrastructure at the Sugar Camp
mine, an Illinois Basin mine also operated by a subsidiary of Foresight Energy. While we own coal reserves at the Williamson and
Macoupin mines, we do not own coal reserves at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a
subsidiary of Foresight Energy and we collect throughput fees. We recorded $23.9 million in revenue related to our coal
transportation and processing assets during the year ended December 31, 2018.
Other Coal Royalty and Other Segment Assets
As of December 31, 2018, we owned an estimated 173 million tons of aggregates reserves primarily located in Kentucky
and Indiana. We lease a portion of these reserves to third parties in exchange for royalty payments. The structure of these leases
is similar to our coal leases, and these leases typically require minimum rental payments in addition to royalties. In addition, we
hold overriding royalty interests in frac sand operations in Wisconsin and Texas and an overriding royalty interest in approximately
82 million tons of sand and gravel reserves in Washington. During 2018, our lessees produced 4.3 million tons from these properties
and we received $4.7 million in aggregates royalty revenues, including overriding royalty revenues.
Through our 51% ownership of BRP LLC ("BRP"), a joint venture with International Paper Company, we own approximately
10 million mineral acres in 31 states that include the following assets:
•
•
•
•
•
•
approximately 300,000 gross acres of oil and natural gas mineral rights primarily in Louisiana, of which over 53,000
acres were leased as of December 31, 2018;
approximately 50 million tons of aggregates reserves primarily located in North Carolina, Arkansas and South Carolina
and approximately 6 million tons of override royalty interest in South Carolina and Georgia;
approximately 95,000 net mineral acres of coal rights (primarily lignite and some bituminous coal) in the Gulf Coast
region, of which approximately 5,600 acres are leased in Louisiana, Mississippi and Texas;
an overriding royalty interest of 1% (net) on approximately 25,000 mineral acres in Louisiana;
copper rights in Michigan’s Upper Peninsula that are subject to a development agreement with a copper development
company; and
various other mineral rights including coalbed methane, metals, aggregates, water and geothermal, in several states
throughout the United States.
While the vast majority of the 10 million acres owned by BRP remain largely undeveloped, BRP has an ongoing program
to identify additional opportunities to lease its minerals to operating parties or otherwise monetize these assets.
14
Soda Ash Segment
We own a 49% non-controlling equity interest in Ciner Wyoming. Ciner Resources LP, our operating partner, controls and
operates Ciner Wyoming. Ciner Resources LP mines the trona, processes it into soda ash, and distributes the soda ash both
domestically and internationally into the glass and chemicals industries. Ciner Resources LP is a publicly traded master limited
partnership that depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders.
Ciner Wyoming is one of the largest and lowest cost producers of soda ash in the world, serving a global market from its
facility located in the Green River Basin of Wyoming. The Green River Basin geological formation holds the largest, and one of
the highest purity, known deposits of trona ore in the world. Trona, a naturally occurring soft mineral, is also known as sodium
sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. Ciner Wyoming processes
trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other
consumer and industrial products. The vast majority of the world’s accessible trona reserves are located in the Green River Basin.
According to historical production statistics, approximately one-quarter of global soda ash is produced by processing trona, with
the remainder being produced synthetically through chemical processes. The costs associated with procuring the materials needed
for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-
based production consumes less energy and produces fewer undesirable by-products than synthetic production.
Ciner Wyoming’s Green River Basin surface operations are situated on approximately 880 acres in Wyoming, and its mining
operations consist of approximately 23,500 acres of leased and licensed subsurface mining area. The facility is accessible by both
road and rail. Ciner Wyoming uses seven large continuous mining machines and 14 underground shuttle cars in its mining operations.
Its processing assets consist of material sizing units, conveyors, calciners, dissolver circuits, thickener tanks, drum filters,
evaporators and rotary dryers.
15
The following map provides an aerial overview of Ciner Wyoming’s surface operations:
In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering the liquor, a solution
consisting of sodium carbonate dissolved in water. Ciner Wyoming then adds activated carbon to filters to remove organic impurities,
which can cause color contamination in the final product. The resulting clear liquid is then crystallized in evaporators, producing
sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge to remove excess water. The
resulting material is dried in a product dryer to form anhydrous sodium carbonate, or soda ash. The resulting processed soda ash
is then stored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. Ciner Wyoming’s
storage silos can hold up to 65,000 short tons of processed soda ash at any given time. The facility is in good working condition
and has been in service for 56 years.
16
Deca Rehydration. The evaporation stage of trona ore processing produces a precipitate and natural by-product called deca.
"Deca," short for sodium carbonate decahydrate, is one part soda ash and ten parts water. Solar evaporation causes deca to crystallize
and precipitate to the bottom of the four main surface ponds at the Green River Basin facility. The deca rehydration process enables
Ciner Wyoming to recover soda ash from the deca-rich purged liquor as a by-product of the refining process. The soda ash contained
in deca is captured by allowing the deca crystals to evaporate in the sun and separating the dehydrated crystals from the soda ash.
The separated deca crystals are then blended with partially processed trona ore in the dissolving stage of the production process.
This process enables Ciner Wyoming to reduce waste storage needs and convert what is typically a waste product into a usable
raw material. Ciner Wyoming anticipates that its current deca stockpiles will be exhausted by 2023. In order to replace the volumes
of soda ash produced from the deca rehydration process following exhaustion of those stockpiles, Ciner Wyoming will need to
make significant capital expenditures over the next few years. See “Item 1A. Risk Factors—Risks Related to Our Business—We
anticipate that Ciner Wyoming will need to increase capital expenditures in order to replace volumes of soda ash currently produced
from the deca rehydration process, which could adversely affect Ciner Wyoming’s profitability and ability to make cash distributions
to us.”
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, 2018, Ciner Wyoming shipped approximately 93.5% of its soda ash to its customers initially via a single
rail line owned and controlled by Union Pacific Railroad Company (“Union Pacific”). The Ciner Wyoming plant receives rail
service exclusively from Union Pacific. The agreement with Union Pacific expires on December 31, 2019 and there can be no
assurance that it will be renewed on terms favorable to Ciner Wyoming or at all. The rail freight rate charged under the agreement
increases annually based on a published index tied to certain rail industry metrics. Ciner Resources Corporation leases a fleet of
more than 2,000 hopper cars that serve as dedicated modes of shipment to its domestic customers. For export, Ciner Wyoming
ships soda ash on unit trains consisting of approximately 100 cars to two primary ports: Port Arthur, Texas and Portland, Oregon.
From these ports, the soda ash is loaded onto ships for delivery to ports all over the world. American Natural Soda Ash Corporation
("ANSAC") currently provides logistics and support services for all of Ciner Wyoming’s export sales. For domestic sales,
Ciner Resources Corporation provides similar services.
Customers. Ciner Wyoming’s customers, including end users to whom ANSAC makes sales overseas, consist primarily of
glass manufacturing companies, which account for 50% or more of the consumption of soda ash around the world; and chemical
and detergent manufacturing companies. Ciner Wyoming’s largest customer currently is ANSAC, which buys soda ash (through
Ciner Resources Corporation, which serves as Ciner Wyoming’s sales agent in its agreement with ANSAC) and other of its member
companies for export to its customers. ANSAC accounted for approximately 52% of Ciner Wyoming’s net sales in 2018. ANSAC
takes soda ash orders directly from its overseas customers and then purchases soda ash for resale from its member companies pro
rata based on each member’s production volumes. ANSAC is the exclusive distributor for its members to the markets it serves.
However, Ciner Resources Corporation, on Ciner Wyoming’s behalf, negotiates directly with, and Ciner Wyoming exports to,
customers in markets not served by ANSAC. During 2017, international sales were made through ANSAC as well as to affiliates
of Ciner Resources Corporation.
In November 2018, Ciner Resources Corporation delivered a notice to terminate the membership in ANSAC, which is
expected to be effective as of December 31, 2021. Until the effective termination date, ANSAC will continue to sell Ciner Wyoming’s
soda ash to ANSAC-designated overseas territories and continue to provide logistics and support services for Ciner Wyoming’s
other export sales. After the termination period, Ciner Resources Corporation will begin marketing soda ash directly into
international markets which are currently being served by ANSAC, and Ciner Wyoming intends to utilize the distribution network
that has already been established by the global Ciner Group. The ANSAC agreement provides that in the event an ANSAC member
exits or the ANSAC cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net
assets or deficit of the cooperative.
For customers in North America, Ciner Resources typically enters into contracts on Ciner Wyoming’s behalf with terms
ranging from one to three years. Under these contracts, customers generally agree to purchase either minimum estimated volumes
of soda ash or a certain percentage of their soda ash requirements at a fixed price for a given calendar year. Although Ciner Wyoming
does not have a “take or pay” arrangements with its customers, substantially all sales are made pursuant to written agreements and
not through spot sales. In 2018, Ciner Wyoming had more than 70 domestic customers and has had long-term relationships with
the majority of its customers.
17
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 Anadarko Petroleum, which are calculated
based upon a percentage of the quantity or gross value of soda ash and related products at a certain stage in the mining process,
or a certain sum per ton of such products. These royalty payments are typically subject to a minimum domestic production volume
from the Green River Basin facility, although Ciner Wyoming is obligated to pay minimum royalties or annual rentals to its lessors
and licensor regardless of actual sales. The royalty rates paid to Ciner Wyoming’s lessors and licensor may change upon renewal
of such leases and license.
As a minority interest owner in Ciner Wyoming, we do not operate and are not involved in the day-to-day operation of the
trona ore mine or soda ash production plant. Our partner, Ciner Resources LP manages the mining and plant operations. We appoint
three of the seven members of the Board of Managers of Ciner Wyoming and have certain limited negative controls relating to the
company.
Significant Customers
We have a significant concentration of revenues with Foresight Energy and its subsidiaries, with total revenues of $54.6
million in 2018 from four different mining operations, including transportation and processing services, coal override and wheelage
revenues. For additional information on significant customers, refer to "Item 8. Financial Statements and Supplementary Data—
Note 16. 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.
Title to Property
We owned substantially all of our coal and aggregates reserves in fee as of December 31, 2018. 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.
18
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.
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, including EPA’s proposed rules to regulate greenhouse gas (GHG) emissions from new and existing fossil fuel-fired
power plants, will 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.
19
Carbon Dioxide and Greenhouse Gas 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 requires 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 is 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.
In October 2015, EPA published its final rule on performance standards for greenhouse gas emissions from new, modified,
and reconstructed electric generating units. The final rule requires new steam generating units to use highly efficient supercritical
pulverized coal boilers that use partial post-combustion carbon capture and storage technology. The final emission standard is less
stringent than EPA had originally proposed due to updated cost assumptions, but could still have a material adverse effect on new
coal-fired power plants. The final rule has been challenged by several states, industry participants and other parties in the United
States Court of Appeals for the District of Columbia Circuit, but is not subject to a stay. In April 2017, the court granted EPA’s
motion to hold the litigation in abeyance while EPA reviews the rule.
President Obama also announced an emission reduction agreement with China’s President Xi Jinping in November 2014.
The United States pledged that by 2025 it would cut climate pollution by 26% to 28% from 2005 levels. China pledged it would
reach its peak carbon dioxide emissions around 2030 or earlier, and increase its non-fossil fuel share of energy to around 20% by
2030. In December 2015, the United States was one of 196 countries that participated in the Paris Climate Conference, at which
the participants agreed to limit their emissions in order to limit global warming to 2°C above pre-industrial levels, with an aspirational
goal of 1.5°C. While there is no way to estimate the impact of these climate pledges and agreements, they could ultimately have
an adverse effect on the demand for coal, both nationally and internationally, if implemented. President Trump has expressed a
desire for the United States to withdraw from the Paris Climate Agreement or to re-negotiate its terms.
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.
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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. In June 2015, EPA issued a new rule defining the
scope of “Waters of the United States” (WOTUS) that are subject to regulation. The WOTUS rule was challenged by a number
of states and private parties in federal district and circuit courts, and the rule was stayed on a nationwide basis by the Sixth Circuit
Court of Appeals in October 2015. In January 2018, the United States Supreme Court ruled that challenges to the WOTUS rule
are properly within the jurisdiction of the federal district courts rather than the Sixth Circuit or other federal appellate courts. In
light of the Supreme Court's ruling, the Sixth Circuit lifted the nationwide stay. In February 2018, EPA and the Corps promulgated
a rule delaying implementation of the 2015 WOTUS rule until 2020 and reinstating the regulatory definition of “Waters of the
United States” that applied prior to the 2015 rule. Several federal district courts have enjoined the suspension rule, resulting in
two different regulatory standards for determining the scope of jurisdiction under the Clean Water Act. Currently, the 2015 WOTUS
rule is in effect in twenty-two states and Washington, D.C., while its predecessor remains in effect in the other twenty-eight. In
December 2017, EPA and the Corps proposed a rule to repeal the WOTUS rule. In December 2018, EPA and the Corps issued a
proposed rule revising the definition of “Waters of the United States.” 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 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.
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 allege violations of water quality standards for selenium, whereas others allege that
discharges of conductivity and sulfate are 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.
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.
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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.
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, 2018, affiliates of our general partner employed 57 people who directly supported our operations. None
of these employees were subject to a collective bargaining agreement.
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Website Access to Partnership Reports
Our Internet address is www.nrplp.com. We make available free of charge on or through our Internet website our Annual
Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not
a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information
statements and other information filed by us.
Corporate Governance Matters
Our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy and our Corporate Governance
Guidelines adopted by our Board of Directors, as well as the charter for our Audit Committee are available on our website at
www.nrplp.com. Copies of our annual report, our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures
Policy, our Corporate Governance Guidelines and our committee charters will be made available upon written request to our
principal executive office at 1201 Louisiana St., Suite 3400, Houston, Texas 77002.
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ITEM 1A.
RISK FACTORS
Risks Related to Our Business
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In
addition, our debt agreements and our partnership agreement place restrictions on our ability to pay, and in some cases raise,
the quarterly distribution under certain circumstances.
Because distributions on the common units are dependent on the amount of cash we generate, distributions fluctuate based
on our performance. The actual amount of cash that is available to be distributed each quarter depends on numerous factors, some
of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow,
and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods
when we record losses and might not be made during periods when we record profits. The actual amount of cash we have to
distribute each quarter is reduced by payments in respect of debt service and other contractual obligations, including distributions
on the preferred units, fixed charges, maintenance capital expenditures and reserves for future operating or capital needs that the
board of directors may determine are appropriate. We have significant debt service obligations and obligations to pay cash
distributions on our preferred units. To the extent our board of directors deems appropriate, it may determine to decrease the amount
of the quarterly distribution on our common units or suspend or eliminate the distribution on our common units altogether. In
addition, because our unitholders are required to pay income taxes on their respective shares of our taxable income, our unitholders
may be required to pay taxes in excess of any future distributions we make. Our unitholders' share of our portfolio income may
be taxable to them even though they receive other losses from our activities. See "—Tax Risks to Our Unitholders—Our unitholders
are required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Our unitholders'
share of our portfolio income may be taxable to them even though they receive other losses from our activities."
The agreements governing our indebtedness and preferred units restrict our ability to raise, and in some cases continue to
pay, distributions on our common units. Opco’s revolving credit agreement, the indenture governing our 2022 Notes and our
partnership agreement each require that we meet certain consolidated leverage tests in order to raise our quarterly distribution on
the common units above the current level of $0.45 per quarter. The maximum leverage covenant under Opco’s revolving credit
facility will step down permanently from 4.0x to 3.0x if we increase the common unit distribution above the current level of $0.45
per common unit per quarter. In addition, under our partnership agreement, to the extent we have paid any distributions on the
preferred units in kind ("PIK units"), and such PIK units are still outstanding at any time after January 1, 2022, we will be prohibited
from making any distributions with respect to our common units until we have redeemed all such PIK units in cash. For more
information on restrictions on our ability to make distributions on our common units, see "Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and "Item 8. Financial Statements
and Supplementary Data—Note 13. Debt, Net."
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business
prospects.
As of December 31, 2018, we and our subsidiaries had approximately $687.1 million of total indebtedness. The terms and
conditions governing the indenture for NRP’s 2022 Notes and Opco’s revolving credit facility and senior notes:
•
•
•
•
•
require us to meet certain leverage and interest coverage ratios;
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing
the cash available to finance our operations and other business activities and could limit our flexibility in planning for
or reacting to changes in our business and the industries in which we operate;
increase our vulnerability to economic downturns and adverse developments in our business;
limit our ability to access the bank and capital markets to raise capital on favorable terms or to obtain additional financing
for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage
in business combinations;
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•
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall
size or less restrictive terms governing their indebtedness;
• make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may
default on our debt obligations; and
•
limit management’s discretion in operating our business.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by
financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic
conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal
and interest on our debt and meet our other obligations, including payment of distributions on the preferred units. If we do not
have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money, or sell assets or raise
equity at unattractive prices, including higher interest rates. We are required to make substantial principal repayments each year
in connection with Opco’s senior notes, with approximately $67 million due thereunder during 2019. In addition, Opco's revolving
credit facility matures in April 2020. To the extent we borrow to make some of these payments, we may not be able to refinance
these amounts on terms acceptable to us, if at all. We may not be able to refinance our debt, sell assets, borrow more money or
access the bank and capital markets on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive
covenants in our debt agreements will be affected by the levels of cash flow from our operations and future events and circumstances
beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such
an event of default could adversely affect our business, financial condition and results of operations.
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;
• 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,
principally into India and northern Europe, has also put downward pressure on thermal coal prices.
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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. Future impairment analyses could result in additional downward adjustments to the carrying
value of our assets.
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, permitting and bonding,
transportation, and labor. Increased costs result in decreased profitability for our lessees and reduce the competitiveness of coal
as a fuel source. In addition, we and our lessees may also incur costs and liabilities resulting from third-party claims for damages
to property or injury to persons arising from their operations. The occurrence of any of these events or conditions could have a
material adverse effect on our business and results of operations.
The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air
pollutants have resulted in changes in fuel consumption patterns by electric power generators and a corresponding decrease
in coal production by our lessees and reduced coal-related revenues.
Enactment of laws and passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states
or other countries, or other actions to limit such emissions, have resulted in and could continue to result in electricity generators
switching from coal to other fuel sources and in coal-fueled power plant closures. Further, regulations regarding new coal-fueled
power plants could adversely impact the global demand for coal. The potential financial impact on us of existing and future laws,
regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to
diminish their reliance on coal as a fuel source. The amount of coal consumed for domestic electric power generation is affected
primarily by the overall demand for electricity, the price and availability of competing fuels for power plants and environmental
and other governmental regulations. We expect that substantially all newly constructed power plants in the United States will be
fired by natural gas because of lower construction and compliance costs compared to coal-fired plants and because natural gas is
a cleaner burning fuel. The increasingly stringent requirements of rules and regulations promulgated under the federal Clean Air
Act have resulted in more electric power generators shifting from coal to natural-gas-fired power plants, or to other alternative
energy sources such as solar and wind. In addition, the Clean Power Plan and proposed rules promulgated by the EPA on greenhouse
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gas emissions from new and existing power plants are expected to further limit the construction of new coal-fired generation plants
in favor of alternative sources of energy and negatively affect the viability of existing coal-fired power generation. 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, which could significantly affect our ability to raise
capital.
Global climate issues continue to attract public and scientific attention. Numerous reports have engendered concern about the
impacts of human activity, especially fossil fuel combustion, on global climate issues. In addition to government regulation of
greenhouse gas and other air pollutant emissions, there have also been efforts in recent years affecting the investment community,
including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the
divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels,
such as coal. The impact of such efforts may adversely affect our ability to raise capital.
In addition 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.
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Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on our
results of operations.
The market price of soda ash directly affects the profitability of Ciner Wyoming’s soda ash production operations. If the
market price for soda ash declines, Ciner Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent,
the domestic market for soda ash have been volatile, and those markets are likely to remain volatile in the future. The prices Ciner
Wyoming receives for its soda ash depend on numerous factors beyond Ciner Wyoming’s control, including worldwide and regional
economic and political conditions impacting supply and demand. Glass manufacturers and other industrial customers drive most
of the demand for soda ash, and these customers experience significant fluctuations in demand and production costs. Competition
from increased use of glass substitutes, such as plastic and recycled glass, has had a negative effect on demand for soda ash.
Substantial or extended declines in prices for soda ash could have a material adverse effect on our results of operations. In addition,
Ciner Wyoming relies on natural gas as the main energy source in its soda ash production process. Accordingly, high natural gas
prices increase Ciner Wyoming’s cost of production and affect its competitive cost position when compared to other foreign and
domestic soda ash producers.
An adverse outcome in our contingent consideration payment dispute with Anadarko could have an adverse effect on our
business and liquidity.
In July 2017, Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, “Anadarko”) filed a
lawsuit against Opco and NRP Trona LLC alleging that a July 2013 simplification of OCI Wyoming’s ownership structure triggered
an acceleration of an obligation under the purchase agreement with Anadarko to pay additional contingent consideration in full
and demanded immediate payment of such amount, together with interest, court costs and attorneys’ fees. We would be required
to pay up to $40 million, plus interest, court costs and attorneys’ fees if Anadarko prevails and is awarded the full damages it seeks.
Any such payment could have a material adverse effect on our financial condition. For more information, see “Item 3. Legal
Proceedings—Anadarko Contingent Consideration Payment Dispute.”
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. In 2018, Contura Energy and Alpha
Natural Resources merged, and our revenues from the two companies on a combined basis accounted for approximately 17% of
our total revenues in 2018. In addition, we own significant interests in all four of Foresight Energy’s mining operations, which
accounted for approximately 22% of our total revenues in 2018. 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 could have a material adverse effect on our business and results of operations.
Due to the continued challenges in the coal business, a number of coal producers filed for protection under U.S. bankruptcy
laws during 2018, including several of our coal lessees. To the extent our leases are accepted or assigned, pre-petition amounts
will 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.
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;
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•
•
•
•
•
•
•
•
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 existing lease
to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell
minerals at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for
small or isolated mineral reserves.
We are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture and
through our ownership of certain coal transportation assets.
We do not have control over the operations of Ciner Wyoming. We have limited approval rights with respect to Ciner Wyoming,
and our partner controls most business decisions, including decisions with respect to distributions and capital expenditures. Adverse
developments in Ciner Wyoming’s business, including increased maintenance and expansion capital expenditures that we may be
required to fund, would result in decreased distributions to NRP. In addition, we are ultimately responsible for operating the
transportation infrastructure at Foresight Energy’s Williamson mine, and have assumed the capital and operating risks associated
with that business. As a result of these investments, we could experience increased costs as well as increased liability exposure
associated with operating these facilities.
A significant portion of Ciner Wyoming’s historical international sales of soda ash have been to ANSAC, and the termination
of the ANSAC membership could adversely affect Ciner Wyoming’s ability to compete in certain international markets and
Ciner Wyoming’s ability to make cash distributions to us.
ANSAC has historically been Ciner Wyoming’s largest customer for the years ended December 31, 2018, 2017 and 2016,
accounting for 52.0%, 44.7% and 55.2%, respectively, of its net sales. Following termination of the membership in ANSAC, which
will be effective December 31, 2021, there is no assurance that Ciner Wyoming will be able to retain existing foreign customers
or secure new foreign customers or the related logistics arrangements on favorable terms. Adverse developments in Ciner
Wyoming’s ability to transport soda ash and sell into the foreign markets currently served by ANSAC could result in lower cash
distributions to us from Ciner Wyoming.
We anticipate that Ciner Wyoming will need to increase capital expenditures in order to replace volumes of soda ash currently
produced from the deca rehydration process, which could adversely affect Ciner Wyoming’s profitability and ability to make
distributions to us.
Ciner Wyoming anticipates that its current deca stockpiles will be exhausted by 2023. In order to replace the volumes of
soda ash produced from the deca rehydration process following exhaustion of those stockpiles, Ciner Wyoming will need to make
significant capital expenditures over the next few years. There is no assurance that any such additional investments will be executed
successfully or in a timely manner to enable Ciner Wyoming to maintain soda ash production levels. In addition, if the capital for
such investment projects cannot be obtained from alternative financing arrangements, Ciner Wyoming’s cash flows may decline,
which could limit Ciner Wyoming’s ability to make cash distributions to us.
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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, 2018, Ciner Wyoming shipped approximately 93.5% 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, 2019. 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.
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:
•
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•
•
•
future prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs;
production levels;
future technology improvements;
the effects of regulation by governmental agencies; and
geologic and mining conditions, which may not be fully identified by available exploration data.
Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations
may be material. As a result, undue reliance should not be placed on our reserve data that is included in this report.
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Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability
to receive amounts in excess of minimum royalty payments.
Mineral supply contracts generally do not require operators to satisfy their obligations to their customers with resources
mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with minerals mined from
properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mine operating
costs, cost and availability of transportation, and customer specifications. In addition, lessees move on and off of our properties
over the course of any given year in accordance with their mine plans. If a lessee satisfies its obligations to its customers with
minerals from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty
revenues.
A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection
process or, if identified, might be identified in a subsequent period.
We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits
and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them
in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and
errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.
Our business is subject to cybersecurity risks.
Our business is increasingly dependent on information technologies and services. Threats to information technology systems
associated with cybersecurity risks and cyber incidents or attacks continue to grow. Although we utilize various procedures and
controls to mitigate our exposure to such risks, cybersecurity attacks and other cyber events are evolving, unpredictable, and
sometimes difficult to detect, and could lead to unauthorized access to sensitive information or render data or systems unusable.
We do not presently maintain insurance coverage to protect against cybersecurity risks. If we procure such coverage in the
future, we cannot ensure that it will be sufficient to cover any particular losses we may experience as a result of such cyber attacks.
Any cyber incident could have a material adverse effect on our business, financial condition and results of operations.
Risks Related to Our Structure
Unitholders may not be able to remove our general partner even if they wish to do so.
Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only
limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of
the general partner on an annual or any other basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical
ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon
the vote of the holders of at least 66 2/3% of our outstanding common units (including common units held by our general partner
and its affiliates and including common units deemed to be held by the holders of the preferred units who vote along with the
common unitholders on an as-converted basis). Because of their substantial ownership in us, the removal of our general partner
would be difficult without the consent of both our general partner and its affiliates and the holders of the preferred units.
In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to
remove our general partner or otherwise change our management:
•
•
generally, if a person (other than the holders of preferred units) acquires 20% or more of any class of units then outstanding
other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and
our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information
about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of
management.
As a result of these provisions, the price at which the common units will trade may be lower because of the absence or
reduction of a takeover premium in the trading price.
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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:
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•
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an existing unitholder’s proportionate ownership interest in NRP will decrease;
the amount of cash available for distribution on each unit may decrease; and
the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common
units may decline.
In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the
preferred will have the right to remove our general partner.
We may issue additional common units or preferred units without common unitholder approval, which would dilute a
unitholder’s existing ownership interests.
Our general partner may cause us to issue an unlimited number of common units, without common unitholder approval
(subject to applicable New York Stock Exchange (NYSE) rules). We may also issue at any time an unlimited number of equity
securities ranking junior or senior to the common units (including additional preferred units) without common unitholder approval
(subject to applicable NYSE rules). In addition, we may issue additional common units upon the exercise of the outstanding
warrants held by Blackstone and Goldentree. The issuance of additional common units or other equity securities of equal or senior
rank will have the following effects:
•
•
•
an existing unitholder’s proportionate ownership interest in NRP will decrease;
the amount of cash available for distribution on each unit may decrease; and
the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common
units may decline.
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.
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Conflicts of interest could arise among our general partner and us or the unitholders.
These conflicts may include the following:
• We do not have any employees and we rely solely on employees of affiliates of the general partner;
•
•
•
•
•
under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the
partnership;
the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly
distributions to unitholders;
the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its
assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach
its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without
limiting the general partner’s liability;
under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and
reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us.
Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arm’s-length
negotiations; and
the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership
interests or by assigning its call rights to one of its affiliates or to us.
In addition, Blackstone has certain consent rights and board appointment and observation rights. GoldenTree also has more
limited consent rights. In the exercise of their applicable consent rights and/or board rights, conflicts of interest could arise between
us and our general partner on the one hand, and Blackstone or GoldenTree on the other hand.
The control of our general partner may be transferred to a third party without unitholder consent. A change of control may
result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation
arrangements.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all
of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability
of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party.
The new owner of our general partner would then be in a position to replace the Board of Directors and officers with its own
choices and to control their decisions and actions.
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.
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Tax Risks to Our Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject
to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as
a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level
taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership
for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would
be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based on
our current operations and current Treasury regulations, we believe we satisfy the qualifying income requirement. However, we
have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the
qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income
tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate and would likely be liable for state income tax at varying rates. Distributions to our unitholders
would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through
to our unitholders. Because tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders
would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated
cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation. Imposition of a similar tax on us in a jurisdiction in which we
operate or in other jurisdictions to which we may expand could substantially reduce the cash available for distribution to our
unitholders.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial
or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units
may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time,
members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly
traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the
qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment
as a partnership for U.S. federal income tax purposes.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect
publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be no assurance that
there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying
income rules in a manner that could impact our ability to qualify as a publicly traded partnership in the future.
However, any interpretation of or modification to the U.S. federal income tax laws may be applied retroactively and could
make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships
for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be
enacted. Any similar or future legislative changes could negatively impact the value of an investment in our units. You are urged
to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and
their potential effect on your investment in our units.
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Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated
as a result of future legislation.
Changes to U.S. federal income tax laws have been proposed in a prior session of Congress that would eliminate certain key
U.S. federal income tax preferences relating to coal exploration and development. These changes include, but are not limited to
(i) repealing capital gains treatment of coal and lignite royalties, (ii) eliminating current deductions and 60-month amortization
for exploration and development costs relating to coal and other hard mineral fossil fuels, and (iii) repealing the percentage depletion
allowance with respect to coal properties. If enacted, these changes would limit or eliminate certain tax deductions that are currently
available with respect to coal exploration and development, and any such change could increase the taxable income allocable to
our unitholders and negatively impact the value of an investment in our units. We are not aware of any current proposals with
regard to these changes.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from
us. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our
activities.
Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than
the cash we distribute, our unitholders are required to pay any federal income taxes and, in some cases, state and local income
taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash
distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that
income.
For our unitholders subject to the passive loss rules, our current operations include portfolio activities (such as our coal and
mineral royalty businesses) and passive activities (such as our soda ash business). Any passive losses we generate will only be
available to offset our passive income generated in the future and will not be available to offset (i) our portfolio income, including
income related to our coal and mineral royalty businesses, (ii) a unitholder’s income from other passive activities or investments,
including investments in other publicly traded partnerships, or (iii) a unitholder’s salary or active business income. Thus, our
unitholders' share of our portfolio income may be subject to federal income tax, regardless of other losses they may receive from
us.
We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including
income and gain from the sale of properties and cancellation of indebtedness income) allocable to our unitholders, and income
tax liabilities arising therefrom may exceed any distributions made with respect to their units.
We may engage in transactions to reduce our leverage and manage our liquidity that would result in income and gain to our
unitholders without a corresponding cash distribution. For example, we may sell assets and use the proceeds to repay existing debt,
in which case, our unitholders could be allocated taxable income and gain resulting from the sale without receiving a cash
distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or
modifications of our existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”)
being allocated to our unitholders as ordinary taxable income. Our unitholders may be allocated income and gain from these
transactions, and income tax liabilities arising therefrom may exceed any distributions we make to our unitholders. The ultimate
tax effect of any such income allocations will depend on the unitholder's individual tax position, including, for example, the
availability of any suspended passive losses that may offset some portion of the allocable income. Our unitholders may, however,
be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against
any capital losses attributable to the unitholder’s ultimate disposition of its units. Our unitholders are encouraged to consult their
tax advisors with respect to the consequences to them
If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the cost
of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes
or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort
to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of
the positions we take. Any contest by the IRS may materially and adversely impact the market for our units and the price at which
they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner
because the costs will reduce our cash available for distribution.
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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
and our current and former unitholders may be required to indemnify us for any taxes (including applicable penalties and
interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.
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 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 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 and our current and former unitholders may be required to indemnify us for any taxes (including any applicable
penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Distributions in excess of a common unitholder's allocable share of our net
taxable income result in a decrease in the tax basis in such unitholder's common units. Accordingly, the amount, if any, of such
prior excess distributions with respect to the common units sold will, in effect, become taxable income to our common unitholders
if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less
than their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our
unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be
taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. Thus, a unitholder may
recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than
such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to
$3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize
ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally
cannot be offset by any capital loss recognized upon the sale of units.
Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or
business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017,
our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.”
For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or
business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation,
amortization, or depletion.
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Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known
as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from
U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable
to them. Further, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, subject to the proposed
aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with
more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged
in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity
separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction).
As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an
investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa.
Tax-exempt entities should consult a tax advisor before investing in our units.
Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our
units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income
effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any
gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result,
distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S.
unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the
sale
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s
sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering
a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the
application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of
regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be
issued. Non-U.S. unitholders should consult a tax advisor before investing in 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.
Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation
and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of
these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our
common units or result in audit adjustments to our unitholders' tax returns.
We 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.
37
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 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 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 subject to state and local taxes and return filing requirements in
jurisdictions where we operate or own or acquire property.
In addition to U.S. federal income taxes, our unitholders are likely subject to other taxes, including state and local taxes,
unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we
conduct business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our
unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these
various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own
property and conduct business in a number of states in the United States. Most of these states impose an income tax on individuals,
corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in
additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal, state and local tax
returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of
such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
38
ITEM 3. LEGAL PROCEEDINGS
NRP is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate
results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a
material effect on the Partnership’s financial position, liquidity or operations. NRP is also currently involved in the legal proceedings
described below.
Foresight Energy Disputes
In October 2018, our lawsuits against Foresight Energy and its subsidiaries Hillsboro Energy and Macoupin Energy were
settled. The Hillsboro suit was pending in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois, and the
Macoupin suit was pending in Macoupin County, Illinois. We received a payment of $25 million from Foresight Energy in full
settlement of the Hillsboro litigation. In addition, we and Hillsboro Energy amended the coal mining lease with respect to the Deer
Run mine to change the $30 million recoupable annual minimum payments to $11 million non-recoupable annual minimum
payments effective January 1, 2019 and extended the current lease term through the end of 2033. Furthermore, Foresight Energy
forfeited its recoupable balances under the Macoupin and Hillsboro leases totaling approximately $37.4 million. All claims were
dismissed in both the Hillsboro and Macoupin lawsuits.
Anadarko Contingent Consideration Payment Dispute
In January 2013, we acquired a non-controlling 48.51% general partner interest in OCI Wyoming, L.P. ("OCI LP") and all
of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited
partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko").
The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical
Corporation.
The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by us if certain
performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015.
For those years, we paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment
obligations.
In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical
Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, we exchanged the stock
of OCI Co for a limited partner interest in OCI LP. Following the reorganization, our interest in OCI LP increased to 49%, consisting
of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues, management
or control of OCI LP.
In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC in the District Court of Harris County, Texas, 157th
Judicial District. The complaint alleged that the transactions conducted in 2013 triggered an acceleration of NRP's obligation under
the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of
such amount, together with interest, court costs and attorneys’ fees. We do not believe the reorganization transactions triggered an
obligation to pay any additional contingent consideration and we are vigorously defending this lawsuit. However, the ultimate
outcome cannot be predicted with certainty and we estimate a possible range of loss between $0, if we prevail, and approximately
$40 million, plus interest, court costs and attorneys’ fees if Anadarko prevails and is awarded the full damages it seeks.
ITEM 4. MINE SAFETY DISCLOSURES
The information concerning mine safety violations or other regulatory matters required by SEC regulations for our construction
aggregates business sold on December 11, 2018 is included in Exhibit 95.1 to this Annual Report on Form 10-K.
39
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
PART II
NRP Common Units
Our common units are listed and traded on the NYSE under the symbol "NRP". As of February 5, 2019, there were
approximately 15,890 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,
2018. The initial number of common units authorized for issuance pursuant to awards under the plan was 800,000.
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights
Weighted-average exercise
price of outstanding
options, warrants and
rights
Number of securities
remaining available for
issuance under equity
compensation plans
(excluding securities
reflected in column (a))
Plan Category
(a)
(b)
(c)
Equity compensation plans approved by security
holders
Equity compensation plans not approved by
security holders
Total
—
n/a
—
—
n/a
—
727,208 (1)
n/a
727,208
(1) As of December 31, 2018, 55,329 unvested phantom units were outstanding under the plan. The phantom units convert into
common units upon vesting on a one-for-one basis.
ITEM 6. SELECTED FINANCIAL DATA
The following table shows selected historical financial data for Natural Resource Partners L.P. for the periods and as of the
dates indicated. We derived the information in the following tables from, and the information should be read together with and is
qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in "Item 8. Financial
Statements and Supplementary Data" in this and previously filed Annual Reports on Form 10-K. These tables should be read
together with "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations."
40
(In thousands, except per unit data)
Total revenues and other income
Asset impairments
Income (loss) from operations
Net income (loss) from continuing
operations
Net income from continuing operations
excluding impairments
Net income (loss) from discontinued
operations
Net income (loss)
Per common unit amounts (basic)
Net income (loss) from continuing
operations
Net income (loss) from discontinued
operations
Net income (loss)
Per common unit amounts (diluted)
Net income (loss) from continuing
operations
Net income (loss) from discontinued
operations
Net income (loss)
Distributions paid per common unit
Average number of common units
outstanding - basic
Average number of common units
outstanding - diluted
Net cash provided by (used in)
Operating activities of continuing
operations
Investing activities of continuing
operations
Financing activities of continuing
operations
Distributable cash flow (3)
Free cash flow (3)
Adjusted EBITDA (3)
Cash, cash equivalents and restricted cash
Total assets
Current portion of long-term debt, net
Long-term debt, net
Class A Convertible Preferred Units
Partners’ capital
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2018 (1) (2)
278,512
18,280
192,538
122,360
140,640
17,687
140,047
7.35
1.42
8.77
5.90
0.86
6.76
1.80
12,244
20,234
178,282
7,607
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
For the Years Ended December 31,
2016 (2)
2015 (2)
2017 (2)
246,325
2,967
176,559
82,485
85,452
6,182
88,667
4.57
0.50
5.06
3.68
0.28
3.96
1.80
12,232
21,950
112,151
9,807
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
279,244
15,861
181,157
90,626
106,487
6,266
96,892
7.28
0.50
7.78
7.28
0.50
7.78
1.80
12,232
12,232
80,243
65,057
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
300,635
378,327
$
(170,699) $
2014 (2)
308,867
26,209
176,108
(260,443) $
96,681
117,884
$
122,890
(311,277) $
(571,720) $
12,149
108,830
(20.80) $
(24.94) $
(45.75) $
(20.80) $
(24.94) $
(45.75) $
$
2.70
12,232
12,232
8.37
1.05
9.42
8.37
1.05
9.42
14.00
11,326
11,326
144,907
15,805
$
$
189,418
1,566
(6,839) $
$
$
$
$
$
$
$
$
$
383,980
183,440
230,241
206,030
1,341,647
115,184
557,574
164,587
423,481
(134,149) $
$
121,958
$
121,324
$
211,483
$
26,980
$
1,389,164
$
79,740
$
729,608
$
173,431
$
265,211
(146,373) $
$
255,172
$
75,970
$
235,273
$
39,171
$
1,448,649
$
140,037
$
990,234
— $
$
151,530
(166,443) $
$
157,815
$
144,210
$
240,553
$
40,244
$
1,674,865
$
80,745
$
1,130,696
— $
$
76,336
(237,314)
195,045
193,665
260,447
45,975
2,431,549
80,745
1,190,558
—
720,155
(1) On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, and all the related amendments
(the “new revenue standard” and "ASC 606") to all open contracts using the modified retrospective method. NRP recognized a $70.5 million cumulative
effect of adoption adjustment in the opening balance of partners' capital on January 1, 2018. Comparative information has not been restated and continues
to be reported under the standards in effect for those periods. Refer to "Item 8. Financial Statements and Supplementary Schedules—Note 2. Summary of
Significant Accounting Policies" and "Item 8. Financial Statements and Supplementary Schedules—Note 3. Revenue from Contracts with Customers" in
this Annual Report on Form 10-K for more information.
(2)
In December 2018, we sold our construction aggregates materials business and have classified the assets and liabilities, operating results and cash flows
of the construction aggregates business as discontinued operations for all periods presented. Refer to "Item 8. Financial Statements and Supplementary
Schedules—Note 4. Discontinued Operations" in this Annual Report on Form 10-K for more information.
(3)
See "—Non-GAAP Financial Measures" below.
41
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 sales of assets, including sales of
discontinued operations, and return of long-term contract receivables (including affiliate); less maintenance capital expenditures
and distributions to non-controlling interest. DCF is not a measure of financial performance under GAAP and should not be
considered as an alternative to cash flows from operating, investing or financing activities. DCF may not be calculated the same
for us as for other companies. 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
(including affiliate); less maintenance and expansion capital expenditures, cash flow used in acquisition costs classified as financing
activities and distributions to non-controlling interest. FCF is calculated before mandatory debt repayments. FCF is not a measure
of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or
financing activities. FCF may not be calculated the same for us as for other companies. FCF is a supplemental liquidity measure
used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts
and others to assess our ability to make cash distributions and repay debt.
The following table reconciles net cash provided by operating activities of continuing operations (the most comparable
GAAP financial measure) to DCF and FCF for the years ended December 31, 2018, 2017, 2016, 2015, and 2014:
2018
2017
2016
2015
2014
Year Ended December 31,
$
178,282
$
112,151
$
80,243
$
144,907
$
189,418
(In thousands)
Net cash provided by operating
activities of continuing operations
Add: distributions from
unconsolidated investment in excess
of cumulative earnings
Add: proceeds from sale of assets
Add: proceeds from sale of
discontinued operations
Add: return of long-term contract
receivables (including affiliates)
Less: maintenance capital
expenditures
Less: distributions to non-controlling
interest
2,097
2,449
5,646
1,151
—
62,117
198,091
—
109,872
3,061
3,010
2,968
—
—
—
—
(28)
—
$
121,958
(1,151)
$
255,172
(62,117)
—
13,605
—
2,463
(416)
3,633
1,380
—
1,904
(316)
(2,744)
157,815
(13,605)
$
(974)
195,045
(1,380)
—
517
(109,872)
(7,213)
75,970
—
—
—
—
$
144,210
$
193,665
Distributable cash flow
$
383,980
$
Less: proceeds from sale of assets
Less: proceeds from sale of
discontinued operations
Less: acquisition costs classified as
financing activities
(2,449)
(198,091)
—
Free cash flow
$
183,440
$
121,324
$
42
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 13. Debt, Net" included elsewhere in this
Annual Report on Form 10-K for a description of Opco’s debt agreements. Adjusted EBITDA is a supplemental performance
measure used by our management and by external users of our financial statements, such as investors, commercial banks, research
analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or
historical cost basis.
The following table reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure)
to Adjusted EBITDA for the years ended December 31, 2018, 2017, 2016, 2015, and 2014:
(In thousands)
Net income (loss) from continuing
operations
Less: equity earnings from
unconsolidated investment
Less: net income attributable to non-
controlling interest
Less: gain on reverse swap
Add: total distributions from
unconsolidated investment
Add: interest expense, net
Add: debt modification expense
Add: loss on extinguishment of debt
Add: depreciation, depletion and
amortization
Add: asset impairments
Adjusted EBITDA
2018
2017
2016
2015
2014
Year Ended December 31,
$
122,360
$
82,485
$
90,626
$
(260,443) $
96,681
(48,306)
(40,457)
(40,061)
(49,918)
(41,416)
(510)
—
46,550
70,178
—
—
21,689
18,280
—
—
49,000
82,028
7,939
4,107
23,414
2,967
—
—
46,550
90,531
—
—
31,766
15,861
—
(9,290)
46,795
89,744
—
—
45,338
378,327
—
(5,690)
46,638
79,427
—
—
58,598
26,209
$
230,241
$
211,483
$
235,273
$
240,553
$
260,447
43
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 10.50% senior notes due
2022 (the "2022 Notes").
44
Executive Overview
We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a
diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash and other natural
resources. 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 in the Northern Powder River Basin in the United
States. Our industrial minerals and aggregates properties are located in a number of states across the United States. Our oil and
gas royalty assets are primarily located in Louisiana.
Soda Ash—consists of our 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the
Green River Basin, Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes
the soda ash both domestically and internationally into the glass and chemicals industries.
In December 2018, we sold our construction aggregates business for $205 million, before customary purchase price
adjustments and transaction expenses, and recorded a gain of $13.1 million. Our exit from the construction aggregates business
enabled us to further reduce debt, focus on our Coal Royalty and Other and Soda Ash business segments and represented a strategic
shift as we exited the operations of our construction aggregates business. As a result, we have classified the assets and liabilities,
operating results and cash flows of the construction aggregates business as discontinued operations in the consolidated financial
statements for all periods presented. See "Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations"
to the audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K for additional information.
Our debt agreements stipulated that 75% of the asset sale proceeds be used to pay down the Opco Revolving Credit Facility and
25% be offered to the holders of the Opco Senior Notes on a pro-rata basis. The outstanding balance on the Opco Revolving Credit
Facility was repaid in December 2018, $49 million was offered to the holders of the Opco Senior Notes in December 2018 and
paid in January 2019, and we intend to use the remaining $55 million of net proceeds to repay the Opco Senior Notes as they
amortize in 2019.
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 and accounting and other
corporate-level activity not specifically allocated to a segment.
Our 2018 financial results by business segment for the year ended December 31, 2018 are as follows:
Operating Segments
(In thousands)
Revenues and other income
Net income (loss) from continuing operations
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)
Soda Ash
Corporate
and
Financing
Total
48,306
48,306
46,550
$
— $ 278,512
$ (86,674) $ 122,360
$ (16,496) $ 230,241
Coal Royalty
and Other
$ 230,206
$ 160,728
$ 200,187
$ 212,394
5,510
$
$
$
$
$
$
$
44,453
2,097
$ (78,565) $ 178,282
7,607
— $
$
(6,839)
(6,839) $
$ (78,565) $ 383,980
$ (78,565) $ 183,440
— $
— $
$ 217,904
$ 215,455
$
$
46,550
46,550
(1) See "Item 6. Selected Financial Data" for additional information regarding non-GAAP financial measures and
reconciliations to the most comparable GAAP financial measures.
45
Current Results/Market Commentary
Coal Royalty and Other Business Segment
Results in 2018 were driven by continued strength in both metallurgical and thermal coal markets. Metallurgical coal prices
of all grades were driven higher from 2017 levels due to worldwide steel production growth along with a muted supply response
from metallurgical coal producers due to various constraints. Benefiting from higher metallurgical coal prices, we derived
approximately 65% of our coal royalty revenues and approximately 55% of our coal royalty production from metallurgical coal
during the year. Looking ahead into 2019, we expect metallurgical coal prices to remain relatively stable due to supportive steel
industry fundamentals combined with logistical and operational supply constraints across the industry. Macro concerns including
slowing GDP growth and trade issues could negatively impact the met market.
The domestic market for thermal coal has benefited from increased export demand from Asia, principally India, and northern
Europe resulting in higher year over year prices in Central and Northern Appalachia, as well as the Illinois Basin. In addition, the
domestic market benefited from higher natural gas prices that increased domestic thermal coal’s competitiveness. However, export
thermal coal prices and domestic natural gas prices are currently down from the highs of 2018 and thermal coal pricing may be
affected accordingly.
Soda Ash Business Segment
Ciner Wyoming's results are primarily affected by the global supply of and demand for soda ash, which in turn directly
impacts the prices Ciner Wyoming and other producers charge for its products. Demand for soda ash in the United States is driven
in a large part by economic growth and activity levels in the end-markets that the glass-making industry serve, such as the automotive
and construction industries. Because the United States is a well-developed market for soda ash, we expect that domestic demand
will remain stable for the near future. Because future United States capacity growth is expected to come from the four major
producers in the Green River Basin, we also expect that U.S. supply levels will remain relatively stable in the near term.
Soda ash demand in international markets has continued to grow in conjunction with GDP. We expect that future global
economic growth will positively influence global demand, which will likely result in increased exports, primarily from the United
States, Turkey and to a limited extent, from China, the largest suppliers of soda ash to international markets.
46
Results of Operations
Year Ended December 31, 2018 and 2017 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,
2018
2017
Increase
(Decrease)
Percentage
Change
$
$
230,206
48,306
278,512
$
$
205,868
40,457
246,325
$
$
24,338
7,849
32,187
12%
19%
13%
The changes in revenues and other income is discussed for each of the operating segments below:
Coal Royalty and Other
The following table presents coal production, coal royalty revenue per ton and coal royalty revenues by major coal producing
region, the significant categories of other revenues and other income:
47
(In thousands, except per ton data)
Coal production (tons)
Appalachia
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder River Basin
Total coal production
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 revenue
Coal royalty adjustment for minimum leases(1)
Total coal royalty revenue
Other revenues
Production lease minimum revenue(1)(2)
Minimum lease straight-line revenue(1)
Property tax revenue
Wheelage revenue
Coal overriding royalty revenue
Lease modification fees(1)
Aggregates royalty revenues
Oil and gas royalty revenues
Other
Total other revenues
Total Coal Royalty and Other revenues
Transportation and processing services
Total Coal Royalty and Other segment revenues
Gain on litigation settlement
Gain on asset sales, net
For the Year Ended December 31,
2018
2017
Increase
(Decrease)
Percentage
Change
3,187
14,997
1,710
19,894
2,739
4,313
26,946
2.74
5.62
7.20
4.63
2.65
4.80
8,719
84,302
12,312
105,333
12,673
11,445
129,451
(110)
129,341
8,207
2,362
5,422
6,484
13,878
—
4,739
6,608
1,837
49,537
178,878
23,887
202,765
25,000
2,441
230,206
$
$
$
$
$
$
$
$
2,136
14,735
2,256
19,127
4,373
4,386
27,886
1.53
5.12
5.94
3.88
2.65
4.33
3,271
75,489
13,399
92,159
16,989
11,642
120,790
—
120,790
30,822
—
5,124
4,734
9,836
1,000
4,241
4,225
1,029
61,011
181,801
20,522
202,323
—
3,545
205,868
$
$
$
$
$
$
$
$
1,051
262
(546)
767
(1,634)
(73)
(940)
1.21
0.50
1.26
0.75
—
0.47
5,448
8,813
(1,087)
13,174
(4,316)
(197)
8,661
(110)
8,551
(22,615)
2,362
298
1,750
4,042
(1,000)
498
2,383
808
(11,474)
(2,923)
3,365
442
25,000
(1,104)
24,338
49 %
2 %
(24)%
4 %
(37)%
(2)%
(3)%
79 %
10 %
21 %
19 %
— %
11 %
167 %
12 %
(8)%
14 %
(25)%
(2)%
7 %
(100)%
7 %
(73)%
100 %
6 %
37 %
41 %
(100)%
12 %
56 %
79 %
(19)%
(2)%
16 %
0.2 %
100 %
(31)%
12 %
$
$
$
$
$
$
$
Total Coal Royalty and Other segment revenues and other income
$
(1) These line items were impacted by the adoption of the new revenue recognition standard effective January 1, 2018. The total impact of
the adoption of this standard in the year ended December 31, 2018 was a net decrease of $55.6 million in Coal Royalty and Other revenues.
For more information on the overall impact of adoption of the new revenue recognition standard and changes to our revenue recognition
policies as a result of this adoption, refer to "Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant
Accounting Policies to the audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
48
(2) Production lease minimum revenue was $30.8 million in 2017 and included any expiration or forfeiture of minimums on all of our leases
under ASC 605. Production lease minimum revenue was $8.2 million in 2018, including expired or forfeited minimums and breakage as
a result of ASC 606. The $22.6 million decrease is primarily due to minimums expiring in 2018 that were included as breakage in the ASC
606 cumulative effect entry to Partners’ capital on January 1, 2018, rather than to production lease minimum revenue.
Coal Royalty Revenue
Coal royalty revenues increased $8.6 million from 2017 to 2018 primarily driven by the following:
• Appalachia: Coal royalty revenue increased $13.2 million as a result of higher metallurgical and thermal coal prices and
higher metallurgical coal production as a result of increased demand primarily in Central and Northern Appalachia,
partially offset by lower thermal coal production as a result of capital constraints and declining overall coal demand for
certain of our lessees which limit their ability to increase production.
•
Illinois Basin: A 37% decrease in production due to the temporary relocation of certain production off of NRP's coal
reserves more than offset the 19% increase in coal royalty price per ton on thermal coal and resulted in a $4.3
million decrease in coal royalty revenue. The decrease in coal royalty revenue was partially offset by a $4.2 million
increase in overriding royalty revenue and wheelage primarily associated with the production of non-NRP coal.
Other Revenues
Total other revenues decreased $11.5 million from 2017 to 2018 primarily as a result of the impact of the new revenue
recognition standard as discussed above. This decrease was partially offset by increased Coal overriding royalty revenue and
Wheelage revenue from the production of non-NRP coal as described above in addition to the increased performance of our natural
gas royalty properties.
Transportation and Processing Services
Transportation and processing services revenue increased $3.4 million from 2017 to 2018 primarily driven by the increase
in tons transported and processed using our assets at the Williamson and Sugar Camp mines and a higher per ton rate at the
Macoupin mine.
Gain on Litigation Settlement
Gain on litigation settlement in the year ended December 31, 2018 related to a one-time payment of $25.0 million we received
from Foresight Energy to settle the Hillsboro lawsuit.
Gain on Asset Sales, Net
Gain on asset sales, net for the segment decreased $1.1 million from 2017 to 2018. Gains on asset sales during the year ended
December 31, 2018 primarily related to the sale of aggregates and other royalty properties and gains on asset sales during the year
ended December 31, 2017 included sales of aggregates royalty properties and condemnation payments.
Soda Ash
Revenues and other income related to our Soda Ash segment increased $7.8 million from 2017 to 2018 primarily as a result
of Ciner Wyoming's litigation settlement of a royalty dispute that resulted in $12.7 million of income. This increase was partially
offset by a $4.9 million decrease in income primarily due to lower production and sales resulting from unexpected equipment
repairs needed, which were resolved during the second quarter of 2018, lower production volume in the third quarter of 2018
primarily due to ore grade degradation, a decrease in international sales prices driven by the absence of international sales to Turkey
and higher selling, general and administrative expenses related to ANSAC, higher employee compensation expense and higher
fees related to Ciner Wyoming's Enterprise Resource Planning project. These decreases were partially offset by lower costs of
products sold as a result of a decrease in freight costs driven by no export volumes to Turkey.
49
Operating and Other Expenses
The table below presents the significant categories of our consolidated operating and other expenses:
(In thousands)
Operating expenses
Operating and maintenance expenses (including affiliates)
Depreciation, depletion and amortization (including affiliates)
General and administrative (including affiliates)
Asset impairments
Total operating expenses
Other expense, net
Interest expense, net
Debt modification expense
Loss on extinguishment of debt
Total other expense, net
For the Year Ended
December 31,
2018
2017
Increase
(Decrease)
Percentage
Change
$
$
29,509
21,689
16,496
18,280
$
24,883
23,414
18,502
2,967
4,626
(1,725)
(2,006)
15,313
$
85,974
$
69,766
$
16,208
$
$
70,178
—
—
82,028
7,939
4,107
$
70,178
$
94,074
$ (11,850)
(7,939)
(4,107)
$ (23,896)
19 %
(7)%
(11)%
516 %
23 %
(14)%
(100)%
(100)%
(25)%
Total operating expenses increased by $16.2 million from 2017 to 2018. The primary reasons for this fluctuation are as
follows:
• Operating and maintenance expenses include costs to manage the Coal Royalty and Other segment and primarily consist
of taxes, royalty, employee related and legal costs. These costs increased $4.6 million primarily due to increased overriding
royalty interest fees, legal costs and property taxes, partially offset by lower bad debt expense.
• Depreciation, depletion and amortization ("DD&A") expense decreased $1.7 million primarily due to a $3.0 million
decrease in depletion expense as a result of lower coal production in the Illinois Basin, partially offset by a $1.3 million
increase on amortization of intangible assets.
• General and administrative ("G&A") expense decreased $2.0 million primarily due to lower employee-related costs year-
over-year.
• Asset impairments increased $15.3 million. Asset impairments in the year ended December 31, 2018 primarily related
to a $13.0 million impairment of an aggregates property that we own and lease to our former construction aggregates
business, which mines, produces and sells the aggregates, in addition to $5.3 million of impairments related to certain of
our coal properties. Asset impairments in the year ended December 31, 2017 primarily consisted of certain coal, aggregates
and timber properties.
Total other expense, net decreased $23.9 million from 2017 to 2018. The primary reasons for this fluctuation are as follows:
•
Interest expense, net decreased $11.9 million primarily due to lower debt balances in 2018 as a result of repayments of
debt.
• Debt modification expense was $7.9 million for the year ended December 31, 2017 and related to costs incurred as a
result of the exchange of $241 million of our 2018 Senior Notes for 2022 Senior Notes in March 2017.
• Loss on extinguishment of debt was $4.1 million for the year ended December 31, 2017 and related to the 4.563% premium
paid to redeem the 2018 Senior Notes in April 2017.
Income from Discontinued Operations
Income from discontinued operations increased $11.5 million primarily as a result of the $13.1 million gain on sale of our
construction aggregates business in the year ended December 31, 2018. This increase was partially offset by decreased net income
from the operations of the construction aggregates business as our construction aggregates business' $5.7 million increase in
operating expenses more than offset its $3.1 million increase in revenues.
50
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, 2018
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
Net income (loss) from continuing operations
$ 160,728
$
Less: equity earnings from unconsolidated investment
Less: net income attributable to non-controlling interest
Add: total distributions from unconsolidated investment
Add: interest expense, net
Add: depreciation, depletion and amortization
Add: asset impairments
—
(510)
—
—
21,689
18,280
48,306
(48,306)
—
46,550
—
—
—
Adjusted EBITDA
December 31, 2017
$ 200,187
$
46,550
Net income (loss) from continuing operations
$ 154,604
$
Less: equity earnings from unconsolidated investment
Add: total distributions from unconsolidated investment
Add: interest expense, net
Add: debt modification expense
Add: loss on extinguishment of debt
Add: depreciation, depletion and amortization
Add: asset impairments
Adjusted EBITDA
—
—
—
—
—
23,414
2,967
40,457
(40,457)
49,000
—
—
—
—
—
$ 180,985
$
49,000
—
$ (86,674) $ 122,360
(48,306)
(510)
46,550
—
—
70,178
—
70,178
21,689
—
18,280
$ (16,496) $ 230,241
$ (112,576) $
—
—
82,028
7,939
4,107
—
82,485
(40,457)
49,000
82,028
7,939
4,107
23,414
—
2,967
$ (18,502) $ 211,483
Adjusted EBITDA increased $18.8 million from 2017 to 2018. The primary reasons for this fluctuation are as follows:
• Coal Royalty and Other segment Adjusted EBITDA increased $19.2 million primarily as a result of the increase in revenues
and other income as discussed above, partially offset by increased operating and maintenance expenses as discussed
above.
•
Soda Ash segment Adjusted EBITDA decreased $2.5 million as a result of lower cash distributions received from Ciner
Wyoming during the year ended December 31, 2018.
• Corporate and financing Adjusted EBITDA increased $2.0 million as a result of the decrease in G&A costs as discussed
above.
See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of Adjusted EBITDA.
51
Distributable Cash Flow ("DCF") and Free Cash Flow ("FCF") (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, 2018
Cash flow provided by (used in) continuing operations
Operating activities
Investing activities
Financing activities
December 31, 2017
Cash flow provided by (used in) continuing operations
Operating activities
Investing activities
Financing activities
Operating Segments
Coal
Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$ 212,394
$
44,453
5,510
—
2,097
—
$ (78,565) $ 178,282
7,607
(6,839)
—
(6,839)
$ 166,138
$
43,354
5,646
$ (97,341) $ 112,151
9,807
(134,149)
—
— (134,666)
4,161
517
52
The following table reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by
business segment to DCF and FCF:
For the Year Ended (In thousands)
December 31, 2018
Net cash provided by (used in) operating activities of continuing
operations
Add: distributions from unconsolidated investment in excess of
cumulative earnings
Add: proceeds from sale of assets
Add: proceeds from sale of discontinued operations
Add: return of long-term contract receivables
Distributable cash flow
Less: proceeds from sale of assets
Less: proceeds from sale of discontinued operations
Free cash flow
December 31, 2017
Net cash provided by (used in) operating activities of continuing
operations
Add: distributions from unconsolidated investment in excess of
cumulative earnings
Add: proceeds from sale of assets
Add: return of long-term contract receivables (including affiliates)
Distributable cash flow
Less: proceeds from sale of assets
Less: acquisition costs classified as financing activities
Free cash flow
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$ 212,394
$
44,453
$ (78,565) $ 178,282
—
2,449
—
3,061
2,097
—
—
—
$ 217,904
(2,449)
—
$
46,550
—
—
$ 215,455
$
46,550
—
—
—
2,097
2,449
198,091
—
3,061
$ (78,565) $ 383,980
(2,449)
—
— (198,091)
$ (78,565) $ 183,440
$ 166,138
$
43,354
$ (97,341) $ 112,151
—
1,151
3,010
5,646
—
—
$ 170,299
(1,151)
517
$
49,000
—
—
$ 169,665
$
49,000
—
—
5,646
1,151
—
3,010
$ (97,341) $ 121,958
(1,151)
517
$ (97,341) $ 121,324
—
—
DCF and FCF increased $262.0 million and $62.1 million, respectively, from 2017 to 2018. The primary reasons for these
fluctuations are as follows:
• Coal Royalty and Other segment DCF and FCF increased $47.6 million and $45.8 million, respectively, primarily due
to a one-time $25 million payment we received from Foresight Energy to settle the Hillsboro lawsuit in addition to
increased cash from coal royalties as a result of higher metallurgical prices and production and increased cash from other
revenues.
•
Soda Ash segment DCF and FCF decreased $2.5 million as a result of lower cash distributions received from Ciner
Wyoming during the year ended December 31, 2018.
• Corporate and Financing DCF and FCF increased $18.8 million primarily as a result of lower performance-based award
payments and lower cash paid for interest year-over-year.
Total DCF was also impacted by the $198.1 million proceeds from the sale of our construction aggregates business in the
year ended December 31, 2018.
See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of Distributable cash flow and
Free cash flow.
53
Results of Operations
Year Ended December 31, 2017 and 2016 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,
2017
2016
Increase
(Decrease)
Percentage
Change
$
$
205,868
40,457
246,325
$
$
239,183
40,061
279,244
$
$
(33,315)
396
(32,919)
(14)%
1 %
(12)%
The changes in revenues and other income is discussed for each of the operating segments below:
54
Coal Royalty and Other
The table below presents coal production, coal royalty revenue per ton and coal royalty revenues by major coal producing
region, the significant categories of other revenues and other income:
For the Year Ended
December 31,
2017
2016
Increase
(Decrease)
Percentage
Change
2,136
14,735
2,256
19,127
4,373
4,386
—
27,886
1.53
5.12
5.94
3.88
2.65
—
4.33
3,271
75,489
13,399
92,159
16,989
11,642
—
120,790
30,822
5,124
4,734
9,836
1,000
4,241
4,225
1,029
61,011
181,801
20,522
202,323
3,545
205,868
$
$
$
$
$
$
$
$
2,312
13,222
2,776
18,310
8,116
3,781
0.4
30,207
1.15
3.64
3.84
3.66
2.81
3.28
3.37
2,667
48,119
10,660
61,446
29,680
10,637
1
101,764
64,591
10,457
2,374
2,281
—
3,163
3,537
2,612
89,015
190,779
19,336
210,115
29,068
239,183
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(176)
1,513
(520)
817
(3,743)
605
(0.4)
(2,321)
0.38
1.48
2.10
0.22
(0.16)
(3.28)
0.96
604
27,370
2,739
30,713
(12,691)
1,005
(1)
19,026
(33,769)
(5,333)
2,360
7,555
1,000
1,078
688
(1,583)
(28,004)
(8,978)
1,186
(7,792)
(25,523)
(33,315)
(8)%
11 %
(19)%
4 %
(46)%
16 %
(100)%
(8)%
33 %
41 %
55 %
6 %
(6)%
(100)%
28 %
23 %
57 %
26 %
50 %
(43)%
9 %
(100)%
19 %
(52)%
(51)%
99 %
331 %
100 %
34 %
19 %
(61)%
(31)%
(5)%
6 %
(4)%
(88)%
(14)%
(In thousands, except per ton data)
Coal production (tons)
Appalachia
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total coal production
Coal royalty revenue per ton
Appalachia
Northern
Central
Southern
Illinois Basin
Northern Powder River Basin
Gulf Coast
Combined average coal royalty revenue per ton
Coal royalty revenues
Appalachia
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total coal royalty revenue
Other revenues
Minimums recognized as revenue
Property tax revenue
Wheelage revenue
Coal overriding royalty revenue
Lease modification fees
Aggregates royalty revenues
Oil and gas royalty revenues
Other
Total other revenues
Coal Royalty and Other revenues
Transportation and processing services
Total Coal Royalty and Other segment revenues
Gain on asset sales, net
Total Coal Royalty and Other segment revenues and other income
55
Coal Royalty Revenue
Coal royalty revenues increased $19.0 million from 2016 to 2017 primarily driven by the following:
• Appalachia: Coal royalty revenue increased $30.7 million as a result of increased metallurgical prices and production.
•
Illinois basin: Lower production partially offset by higher royalty revenue per ton led to a $12.7 million decrease in coal
royalty revenue. The decreased production was primarily as a result of the temporary relocation of certain production off
NRP's coal reserves, which resulted in a $7.5 million increase in coal overriding royalty revenue and wheelage associated
with the production of non-NRP coal.
Other Revenues
Total other revenues decreased $28.0 million primarily as a result of a $33.8 million decrease in minimums recognized as
revenue due to certain lease modifications and terminations in the second quarter of 2016 and a $5.3 million decrease in property
tax reimbursements. The decrease in property tax revenue was fully offset by lower property tax expenses as described in operating
and maintenance expenses below. These decreases were partially offset by an increase in coal override revenue and wheelage as
discussed above.
Transportation and Processing Services
Transportation and processing services revenue increased $1.2 million from 2016 to 2017 primarily driven by the increase
in tons transported and processed using our assets at the Williamson mine.
Gain on Asset Sales, Net
Gain on asset sales, net decreased $25.5 million from 2016 to 2017 primarily as a result of numerous asset sales completed
during the year ended December 30, 2016, including an $18.6 million gain on the sale of oil and gas royalty and overriding royalty
interests in the Appalachian Basin.
Operating and Other Expenses
The table below presents the significant categories of our consolidated operating and other expenses:
For the Year Ended
December 31,
2017
2016
Increase
(Decrease)
Percentage
Change
$
$
24,883
23,414
18,502
2,967
29,890
31,766
20,570
15,861
$
69,766
$
98,087
$
(5,007)
(8,352)
(2,068)
(12,894)
$ (28,321)
(17)%
(26)%
(10)%
(81)%
(29)%
(9)%
100 %
100 %
4 %
(In thousands)
Operating expenses
Operating and maintenance expenses (including affiliates)
Depreciation, depletion and amortization (including affiliates)
General and administrative (including affiliates)
Asset impairments
Total operating expenses
Other expense, net
Interest expense, net (including affiliates)
$
82,028
$
90,531
$
Debt modification expense
Loss on extinguishment of debt
Total other expense, net
7,939
4,107
—
—
$
94,074
$
90,531
$
(8,503)
7,939
4,107
3,543
56
Total operating expenses decreased $28.3 million from 2016 to 2017. The primary reasons for these fluctuations are as
follows:
• Operating and maintenance expenses decreased $5.0 million primarily due to $5.8 million lower property tax expense as
a result of lower property tax rates and property tax values primarily in Kentucky and West Virginia and lower employee
related costs.
• DD&A expense decreased $8.4 million driven primarily by lower coal production in the Illinois Basin.
• G&A expense decreased $2.1 million primarily due to decreased legal, consulting and advisory fees incurred in 2016 as
a result of the recapitalization transactions completed in March 2017.
• Asset impairments decreased $12.9 million. Asset impairments in the year ended December 31, 2017 primarily consisted
of certain coal, aggregates and timber properties and asset impairments in the year ended December 31, 2016 primarily
consisted of certain coal and aggregates properties.
Total other expense, net increased $3.5 million from 2016 to 2017. The primary reasons for these fluctuations are as follows:
•
Interest expense, net decreased $8.5 million primarily related to lower debt balances during 2017 as a result of the
recapitalization transactions entered into in March 2017.
• Debt modification expense was $7.9 million for the year ended December 31, 2017 and related to costs incurred as a
result of the exchange of $241 million of our 2018 Senior Notes for 2022 Senior Notes in March 2017.
• Loss on extinguishment of debt was $4.1 million for the year ended December 31, 2017 and related to the 4.563% premium
paid to redeem the 2018 Senior Notes in April 2017.
Income from Discontinued Operations
Income from discontinued operations was essentially flat from 2016 to 2017. Income related to our non-operated oil and gas
working interest assets decreased $2.2 million as a result of the sale of these assets in July 2016 while income related to our
construction aggregates business increased $2.1 million as a result of increased crushed stone, sand and gravel sales volumes year-
over-year.
57
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, 2017
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Net income (loss) from continuing operations
$ 154,604
$
Less: equity earnings from unconsolidated investment
Add: total distributions from unconsolidated investment
Add: interest expense, net
Add: debt modification expense
Add: loss on extinguishment of debt
Add: depreciation, depletion and amortization
Add: asset impairments
—
—
—
—
—
23,414
2,967
40,457
(40,457)
49,000
—
—
—
—
—
Adjusted EBITDA
December 31, 2016
$ 180,985
$
49,000
Net income (loss) from continuing operations
$ 161,666
$
Less: equity earnings from unconsolidated investment
Add: total distributions from unconsolidated investment
Add: interest expense, net
Add: depreciation, depletion and amortization
Add: asset impairments
Adjusted EBITDA
—
—
—
31,766
15,861
40,061
(40,061)
46,550
—
—
—
$ 209,293
$
46,550
Total
82,485
(40,457)
49,000
82,028
7,939
4,107
23,414
$ (112,576) $
—
—
82,028
7,939
4,107
—
—
2,967
$ (18,502) $ 211,483
$ (111,101) $
—
—
90,531
—
90,626
(40,061)
46,550
90,531
31,766
—
15,861
$ (20,570) $ 235,273
Adjusted EBITDA decreased $23.8 million from 2016 to 2017. The primary reasons for these fluctuations are as follows:
• Coal Royalty and Other segment Adjusted EBITDA decreased $28.3 million. While performance of our coal-related
assets improved as described above, the prior year amount included $40.5 million of revenue resulting from one-time
lease modifications and $25.5 million higher gains on asset sales, net.
•
Soda Ash segment Adjusted EBITDA increased $2.5 million as a result of increased cash distributions received in the
year ended December 31, 2017.
• Corporate and financing Adjusted EBITDA increased $2.1 million primarily due to legal and consulting fees related to
the recapitalization activities incurred in 2016.
See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of Adjusted EBITDA.
58
Distributable Cash Flow ("DCF") and Free Cash Flow ("FCF") (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, 2017
Cash flow provided by (used in) continuing operations
Operating activities
Investing activities
Financing activities
December 31, 2016
Cash flow provided by (used in) continuing operations
Operating activities
Investing activities
Financing activities
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$ 166,138
$
43,354
4,161
517
5,646
$ (97,341) $ 112,151
9,807
(134,149)
—
— (134,666)
$ 134,490
$
46,550
$ (100,797) $
80,243
65,057
16
—
(7,229)
—
(139,160)
65,057
(146,373)
59
The following table reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by
business segment to DCF and FCF:
For the Year Ended (In thousands)
December 31, 2017
Net cash provided by (used in) operating activities of continuing
operations
Add: distributions from unconsolidated investment in excess of
cumulative earnings
Add: proceeds from sale of assets
Add: return of long-term contract receivables (including affiliates)
Distributable cash flow
Less: proceeds from sale of assets
Less: acquisition costs classified as financing activities
Free cash flow
December 31, 2016
Net cash provided by (used in) operating activities of continuing
operations
Add: proceeds from sale of assets
Add: proceeds from sale of discontinued operations
Add: return of long-term contract receivables—affiliate
Less: maintenance capital expenditures
Distributable cash flow
Less: proceeds from sale of assets
Less: proceeds from sale of discontinued operations
Less: acquisition costs classified as financing activities
Free cash flow
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$ 166,138
$
43,354
$ (97,341) $ 112,151
—
1,151
3,010
5,646
—
—
$ 170,299
(1,151)
517
$
49,000
—
—
$ 169,665
$
49,000
—
—
5,646
1,151
—
3,010
$ (97,341) $ 121,958
(1,151)
517
$ (97,341) $ 121,324
—
—
$ 134,490
$
46,550
$ (100,797) $
80,243
62,117
—
2,968
(28)
$ 199,547
(62,117)
—
16
$
$ 137,446
$
—
—
—
—
46,550
—
—
(7,229)
39,321
—
—
62,117
109,872
—
—
2,968
(28)
$ (100,797) $ 255,172
(62,117)
—
— (109,872)
(7,213)
—
75,970
$ (100,797) $
DCF decreased $133.2 million from 2016 to 2017. This decrease is due primarily to the $109.9 million proceeds from the
sale of our non-operated oil and gas working interest assets in 2016 in addition to the following:
• Coal Royalty and Other segment DCF decreased $29.2 million primarily due to $61.0 million higher proceeds from asset
sales in 2016 as compared to 2017, partially offset by a $31.6 increase in cash provided by operating activities as a result
of improved performance of segment assets in 2017.
• Corporate and Financing DCF increased $3.5 million primarily as a result of lower cash paid for interest and lower legal,
consulting and advisory fees following the completion of the recapitalization transactions in March 2017.
•
Soda Ash DCF increased $2.5 million as a result of higher cash distributions received from Ciner Wyoming in 2017.
FCF increased $45.4 million primarily as a result of the $31.6 million increase in cash provided by operating activities from
the Coal Royalty and Other segment. FCF also increased as a result of the $7.2 million cash paid for acquisition costs in our Soda
Ash segment in 2016, in addition to higher cash distributions received from Ciner Wyoming in 2017 and the $3.5 million increase
in operating cash flows related to lower cash paid for interest and lower legal, consulting and advisory fees following the completion
of the recapitalization transactions in March 2017.
See "Item 6. Selected Financial Data—Non-GAAP Financial Measures" for an explanation of Distributable cash flow and
Free cash flow.
60
Liquidity and Capital Resources
Current Liquidity
As of December 31, 2018, we had total liquidity of $306.0 million, consisting of $101.8 million of cash and cash equivalents,
$104.2 million of restricted cash and $100.0 million in borrowing capacity under our Opco Credit Facility. The $104.2 million of
restricted cash represents the remaining net proceeds from the sale of our construction aggregates business that is required to be
used to repay debt, make acquisitions or make capital expenditures per the terms of our debt agreements. In January 2019, we
used approximately $49 million of this restricted cash to repay principal amounts on the Opco Senior Notes, and we intend to use
the remaining $55 million to repay the Opco Senior Notes as they amortize in 2019. We remain focused on further reducing our
debt and improving our liquidity metrics.
Cash Flows
Cash flows provided by operating activities increased $61.8 million, from $127.1 million in the year ended December 31,
2017 to $188.9 million in the year ended December 31, 2018 primarily related to increased operating cash flows in our Coal
Royalty and Other segment as a result of a one-time $25 million payment we received from Foresight Energy to settle the Hillsboro
lawsuit in addition to increased cash from coal royalties as a result of higher metallurgical prices and production and increased
cash from other revenues. Also contributing to the increase in cash provided by operating activities was the decrease in G&A
payments primarily as a result of the payment of the performance-based awards in 2017 following the completion of our
recapitalization transactions in addition to lower cash paid for interest on our debt.
Cash flow provided by operating activities increased $19.2 million, from $108.0 million in the year ended December 31,
2016 to $127.1 million in the year ended December 31, 2017. Cash flows from continuing operations increased $31.9
million primarily from increased operational performance from our Coal Royalty and Other segment assets year-over-year. This
increase was partially offset by a $12.7 million decrease in operating cash flow from discontinued operations primarily due to cash
flows from our non-operated oil and gas working interest assets prior to their sale in 2016.
Cash flow provided by investing activities increased $187.1 million, from $3.5 million in the year ended December 31, 2017
to $190.6 million in the year ended December 31, 2018. Cash flows from discontinued operations increased $189.3 million as a
result of the $198.1 million proceeds received from the sale of our construction aggregates business in December 2018, partially
offset by increased construction aggregates capital expenditures during 2018. Cash flows from continuing operations decreased
$2.2 million primarily due to a lower portion of our distribution from Ciner Wyoming classified as an investing activity in 2018.
Cash flow provided by investing activities decreased $163.3 million, from $166.8 million in the year ended December 31,
2016 to $3.5 million in the year ended December 31, 2017. Investing cash flows from discontinued operations decreased $108.0
million primarily as a result of the $109.9 million proceeds received from the sale of our non-operated oil and gas working interest
assets in the year ended December 31, 2016. Investing cash flows from continuing operations decreased $55.3 million primarily
as a result of the proceeds received in 2016 from the sales of our oil and gas royalty and overriding royalty and aggregates royalty
properties.
Cash flows used in financing activities increased $62.1 million, from $141.2 million in the year ended December 31, 2017
to $203.3 million in the year ended December 31, 2018 primarily due to the proceeds received in 2017 related to recapitalization
transactions, partially offset by the first quarter 2017 debt repayments and debt issuance costs paid as a result of the March 2017
recapitalization transactions. Cash flow used in financing activities also increased as a result of the $21.4 million increase in
preferred unit distributions and the $8.8 million redemption of the PIK units in the year ended December 31, 2018.
Cash flow used in financing activities decreased $145.0 million from $286.2 million in the year ended December 31, 2016
to $141.2 million in the year ended December 31, 2017. This decrease in cash flow used is primarily due to the proceeds received
from the issuance of Preferred Units and warrants and 2022 Senior Notes in 2017. These proceeds were partially offset by additional
debt repayments and debt issuance costs paid in the first quarter of 2017 as a result of the March 2017 recapitalization transactions.
61
Capital Resources and Obligations
Debt
We had the following debt outstanding as of December 31, 2018 and 2017:
(In thousands)
Current portion of long-term debt, net
Long-term debt, net
Total debt, net
December 31,
2018
2017
$
$
115,184
557,574
672,758
$
$
79,740
729,608
809,348
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 13. Debt, Net" in this Annual Report on Form 10-K.
Long-Term Contractual Obligations
The following table reflects our long-term, non-cancelable contractual obligations as of December 31, 2018:
Contractual Obligations (In thousands)
NRP:
Long-term debt principal payments
(including current maturities) (1)
Long-term debt interest payments (1)
Opco:
Long-term debt principal payments
(including current maturities) (2)
Long-term debt interest payments (3)
Total
Total
2019
2020 (4)
2021
2022
2023
Thereafter
Payments Due by Period
$ 345,638
$
— $
— $
— $ 345,638
$
— $
127,022
36,292
36,292
36,292
18,146
—
—
—
341,500
54,476
116,125
16,018
46,436
12,013
39,634
9,421
39,634
7,172
39,634
4,923
60,037
4,929
$ 868,636
$ 168,435
$ 94,741
$ 85,347
$ 410,590
$ 44,557
$ 64,966
(1) The amounts indicated in the table include principal and interest due on NRP’s 2022 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.
(4) Not included in the table above is the Opco Credit Facility, which matures on April 30, 2020. At December 31, 2018 we
did not have any borrowings outstanding under the Opco Credit Facility and have $100.0 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, 2018, 2017 and 2016.
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."
62
Related Party Transactions
The information required by this Item is included under "Item 8. Financial Statements and Supplementary Data—Note 15.
Related Party Transactions" and "Item 13. Certain Relationships and Related Transactions, and Director Independence" in this
Annual Report on Form 10-K and is incorporated by reference herein.
Summary of Critical Accounting Policies
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. In accordance with previous accounting standards in effect prior to January 1, 2018, we recognized
all coal and aggregates royalty revenue over the lease term based on production. The recognition of revenue from minimum
payments was deferred until either recoupment through royalty production occurred or when the recoupment period expired for
unrecouped minimums. Under the new revenue recognition standard, 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 revenue or Aggregates royalty revenue, as applicable. Deferred revenue from minimums is recognized
as royalty revenue when recoupment occurs or as Production lease minimum revenue 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 revenue.
• 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 revenue.
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 revenue from those sales. Also, included within oil and gas royalties
are lease bonus payments, which are generally paid upon the execution of a lease. We also have overriding royalty revenue interests
in coal reserves. Revenue from these interests is recognized over time based on when the coal is sold.
63
Wheelage. Revenue 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 revenue. Other revenue 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.
Transportation and processing services revenue. 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, forfeiture
of recoupment rights or termination due to the exhaustion of merchantable and mineable reserves. 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 modification fees within Coal
royalty and other revenues on our Consolidated Statements of Comprehensive Income while modifications in royalty rates and
minimums will be recognized prospectively in accordance with the above lease classification.
In accordance with the transition guidance in paragraph 606-10-65-1, revenues from contracts that were modified before
January 1, 2018 were not retrospectively restated for those modifications and instead reflected the aggregate effect of those
modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and
allocating the transaction price to the satisfied and unsatisfied performance obligation.
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 modification 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 modification 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 revenue 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.
64
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 in 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 in the Consolidated Statements of Comprehensive Income. We increase 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 beyond our control.
Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which
may, if incorrect, result in an estimate that varies considerably from actual results.
Asset Impairment
We have developed procedures to evaluate our long-lived assets for possible impairment periodically or whenever events
or changes in circumstances indicate an asset's carrying amount 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 assets’ carrying 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 assets’ carrying 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
We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:
Commodity Price Risk
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend
substantially on prevailing commodity prices. Historically, coal prices have been volatile, with prices fluctuating widely, and they
65
are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results.
In particular, substantially lower prices would significantly reduce revenue and could potentially trigger an impairment of our coal
properties or a violation of certain financial debt covenants. Because substantially all of our reserves are coal, changes in coal
prices have a more significant impact on our financial results.
We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various
long-term and short-term contracts as well as on the spot market. Current conditions in the coal industry may make it difficult for
our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees’ failure to negotiate
long-term contracts could adversely affect the stability and profitability of our lessees’ operations and adversely affect our future
financial results. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in
spot coal prices.
The market price of soda ash directly affects the profitability of Ciner Wyoming’s operations. If the market price for soda
ash declines, Ciner Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for
soda ash have been volatile, and those markets are likely to remain volatile in the future.
Interest Rate Risk
Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to
variable interest rates based upon LIBOR. At December 31, 2018 we did not have any borrowings outstanding under the Opco
Credit Facility.
Fair Value of Financial Assets and Liabilities
Our financial assets and liabilities consist of cash and cash equivalents, restricted cash, contracts receivable, debt, Preferred
Units and Warrants. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents and restricted
cash approximate fair value due to their short-term nature.
We use available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the
estimated amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the
issue rate and the period end market rate. The credit spread is our default or repayment risk. The following table shows the carrying
amount and estimated fair value of our debt and contracts receivable:
(In thousands)
Debt:
NRP 2022 Senior Notes (1)
Opco Senior Notes (2)
Opco Revolving Credit Facility (3)
Assets:
Contracts receivable, current and long-term (4)
$
$
December 31, 2018
December 31, 2017
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
$
334,024
338,734
—
$
356,871
352,599
—
$
330,404
418,944
60,000
366,376
447,538
60,000
40,776
$
34,704
$
43,826
$
30,517
(1) The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period
end.
(2) Due to no observable quoted prices on these instruments, the Level 3 fair value is estimated by management using quotations
obtained for the NRP Senior Notes on the closing trading prices near period end.
(3) The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective
of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.
(4) The Level 3 fair value is determined based on the present value of future cash flow projections related to the underlying
assets.
66
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, 2018 and 2017
Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Partners’ Capital for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
Page
68
69
70
71
72
73
75
67
Report of Independent Registered Public Accounting Firm
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, 2018 and 2017, the related consolidated statements of comprehensive income, partners’ capital and cash flows for
each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of
its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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 $247 million and $245 million as of December 31, 2018 and 2017, respectively, and the Partnership’s equity in the net income
of Ciner Wyoming is stated at $48 million in 2018, $40 million in 2017 and $40 million in 2016. 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, 2018, 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 7, 2019 expressed an unqualified opinion thereon.
Adoption of ASU No. 2014-09
As discussed in Note 2 to the consolidated financial statements, the Partnership adopted ASU No. 2014-09, “Revenue from Contracts
with Customers (Topic 606)” effective January 1, 2018. As a result, for the year ended December 31, 2018, the Partnership changed
its method for revenue recognition related to royalty lease arrangements.
Basis for Opinion
These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on
the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error
or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether
due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2002.
Houston, Texas
March 7, 2019
68
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ciner Wyoming LLC (“the Company”) as of December 31, 2018 and 2017,
and the related statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years
in the period ended December 31, 2018 and the related notes included in Exhibit 99.1 (collectively referred to as the "financial
statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company
as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period
ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required
to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are
required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion
on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due
to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 7, 2019
We have served as the Company’s auditor since 2008.
69
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data)
ASSETS
Current assets
Cash and cash equivalents
Restricted cash
Accounts receivable, net
Accounts receivable—affiliates
Prepaid expenses and other
Current assets of discontinued operations
Total current assets
Land
Plant and equipment, net
Mineral rights, net
Intangible assets, net
Equity in unconsolidated investment
Long-term contracts receivable
Long-term assets of discontinued operations
Other assets
Other assets—affiliate
Total assets
LIABILITIES AND CAPITAL
Current liabilities
Accounts payable
Accounts payable—affiliates
Accrued liabilities
Accrued liabilities—affiliates
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
Long-term liabilities of discontinued operations
Other non-current liabilities
Other non-current liabilities—affiliate
Total liabilities
Commitments and contingencies (see Note 17)
Class A Convertible Preferred Units (250,000 and 258,844 units issued and outstanding at
December 31, 2018 and 2017, respectively, at $1,000 par value per unit; liquidation
preference of $1,500 per unit)
Partners’ capital
Common unitholders’ interest (12,249,469 and 12,232,006 units issued and outstanding
at December 31, 2018 and 2017, respectively)
General partner’s interest
Warrant holders’ interest
Accumulated other comprehensive loss
Total partners’ capital
Non-controlling interest
Total capital
Total liabilities and capital
December 31,
2018
2017
101,839
104,191
32,024
34
3,462
993
242,543
24,008
984
743,112
42,513
247,051
38,945
—
2,491
—
1,341,647
548
1,866
12,347
—
14,345
3,509
115,184
947
148,746
49,044
557,574
—
1,150
—
756,514
$
$
$
$
$
$
26,980
—
24,050
161
3,782
36,423
91,396
24,008
1,348
778,419
46,820
245,433
40,776
155,942
4,866
156
1,389,164
1,010
490
11,542
515
15,484
—
79,740
11,768
120,549
100,605
729,608
2,220
588
346
953,916
164,587
$
173,431
355,113
5,014
66,816
(3,462)
423,481
(2,935)
420,546
1,341,647
$
$
$
199,851
1,857
66,816
(3,313)
265,211
(3,394)
261,817
1,389,164
$
$
$
$
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
70
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands, except per unit data)
Revenues and other income
Coal royalty and other
Coal royalty and other—affiliates
Transportation and processing services
Transportation and processing services—affiliate
Equity in earnings of Ciner Wyoming
Gain on litigation settlement
Gain on asset sales, net
Total revenues and other income
Operating expenses
Operating and maintenance expenses
Operating and maintenance expenses—affiliates
Depreciation, depletion and amortization
Amortization expense—affiliate
General and administrative
General and administrative—affiliates
Asset impairments
Total operating expenses
Income from operations
Other expense, net
Interest expense, net
Interest expense—affiliate
Debt modification expense
Loss on extinguishment of debt
Total other expense, net
Net income from continuing operations
Income from discontinued operations (see Note 4)
Net income
Less: net income attributable to non-controlling interest
Net income attributable to NRP
Less: income attributable to preferred unitholders
Net income attributable to common unitholders and general partner
Net income attributable to common unitholders
Net income attributable to the general partner
Income from continuing operations per common unit (see Note 7)
Basic
Diluted
Net income per common unit (see Note 7)
Basic
Diluted
Net income
Comprehensive income (loss) from unconsolidated investment and
other
Comprehensive income
Less: comprehensive income attributable to non-controlling interest
Comprehensive income attributable to NRP
For the Years Ended December 31,
2018
2017
2016
178,394
484
23,887
—
48,306
25,000
2,441
278,512
17,894
11,615
21,689
—
12,838
3,658
18,280
85,974
192,538
$
$
$
$
$
158,399
23,402
14,510
6,012
40,457
—
3,545
246,325
16,771
8,112
22,406
1,008
13,513
4,989
2,967
69,766
176,559
$
$
$
$
$
(70,178) $
—
—
—
(70,178) $
(82,028) $
—
(7,939)
(4,107)
(94,074) $
122,360
17,687
140,047
(510)
139,537
(30,000)
109,537
107,346
2,191
7.35
5.90
8.77
6.76
$
$
$
$
$
$
$
82,485
6,182
88,667
—
88,667
(25,453)
63,214
61,950
1,264
4.57
3.68
5.06
3.96
$
$
$
$
$
$
$
144,520
46,259
—
19,336
40,061
—
29,068
279,244
20,737
9,153
28,581
3,185
16,979
3,591
15,861
98,087
181,157
(90,008)
(523)
—
—
(90,531)
90,626
6,266
96,892
—
96,892
—
96,892
95,229
1,663
7.28
7.28
7.78
7.78
140,047
$
88,667
$
96,892
(149)
139,898
(510)
139,388
$
$
(1,647)
87,020
—
87,020
$
$
486
97,378
—
97,378
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
71
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Balance at December 31, 2015
Net income
Distributions to common
unitholders and general partner
Non-cash contributions
Comprehensive income 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
—
$ 79,094
95,229
$
(606) $
1,663
— $
—
(2,152) $
—
76,336
96,892
$
(3,394) $ 72,942
96,892
—
— (22,014)
—
—
—
—
(451)
281
—
—
—
—
—
—
(22,465)
281
486
486
— (22,465)
—
—
281
486
Balance at December 31, 2016
12,232
$152,309
$
887
$
— $
(1,666) $ 151,530
$
(3,394) $ 148,136
Net income (1)
Distributions to common
unitholders and general partner
Distributions to preferred
unitholders
Issuance of Warrants
Comprehensive loss from
unconsolidated investment and
other
—
86,894
1,773
— (22,018)
(449)
— (17,334)
(354)
—
—
—
—
—
—
—
66,816
—
—
—
—
88,667
—
88,667
(22,467)
— (22,467)
(17,688)
66,816
— (17,688)
—
66,816
—
—
(1,647)
(1,647)
—
(1,647)
Balance at December 31, 2017
12,232
$199,851
$ 1,857
$ 66,816
$
(3,313) $ 265,211
$
(3,394) $ 261,817
Cumulative effect of adoption
of accounting standard (See
Note 3)
Net income (2)
Distributions to common
unitholders and general partner
Distributions to preferred
unitholders
Issuance of unit-based awards
Unit-based awards amortization
and vesting
Comprehensive income (loss)
from unconsolidated investment
and other
—
69,057
— 136,746
1,409
2,791
— (22,036)
(450)
— (29,660)
546
17
—
—
560
49
(605)
—
—
12
—
—
—
—
—
—
—
—
—
—
—
—
—
70,466
139,537
—
510
70,466
140,047
(22,486)
— (22,486)
(30,265)
— (30,265)
546
560
—
—
546
560
(149)
(88)
(51)
(139)
Balance at December 31, 2018
12,249
$355,113
$ 5,014
$ 66,816
$
(3,462) $ 423,481
$
(2,935) $ 420,546
(1) Net income for the year ended December 31, 2017 includes $25.5 million attributable to Preferred Unitholders that accumulated
during the period, of which $24.9 million is allocated to the common unitholders and $0.5 million is allocated to the general
partner.
(2) Net income for the year ended December 31, 2018 includes $30.0 million attributable to Preferred Unitholders that accumulated
during the period, of which $29.4 million is allocated to the common unitholders and $0.6 million is allocated to the general
partner.
The accompanying notes are an integral part of these consolidated financial statements.
72
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating
activities of continuing operations:
Years Ended December 31,
2018
2017
2016
$
140,047
$
88,667
$
96,892
21,689
—
44,453
(48,306)
(2,441)
—
—
(17,687)
18,280
1,434
7,334
(201)
(6,251)
127
(238)
1,376
134
(115)
(1,138)
—
19,465
—
320
178,282
10,641
188,923
2,097
2,449
3,061
—
—
$
$
$
22,406
1,008
43,354
(40,457)
(3,545)
7,939
4,107
(6,182)
2,967
18
9,077
1,207
5,905
367
(185)
1
(8,478)
515
(105)
—
(5,791)
(10,166)
(478)
112,151
14,988
127,139
5,646
1,151
2,206
804
—
$
$
$
7,607
$
9,807
$
28,581
3,185
46,550
(40,061)
(29,068)
—
—
(6,266)
15,861
1,217
8,638
993
1,545
(313)
517
—
3,628
—
(779)
(456)
(35,881)
(12,063)
(2,477)
80,243
27,718
107,961
—
62,117
—
2,968
(28)
65,057
183,021
190,628
$
(6,264)
3,543
$
101,758
166,815
Depreciation, depletion and amortization
Amortization expense—affiliate
Distributions from unconsolidated investment
Equity earnings from unconsolidated investment
Gain on asset sales, net
Debt modification expense
Loss on extinguishment of debt
Income from discontinued operations
Asset impairments
Unit-based compensation expense
Amortization of debt issuance costs and other
Other—affiliates
Change in operating assets and liabilities:
Accounts receivable
Accounts receivable—affiliates
Accounts payable
Accounts payable—affiliates
Accrued liabilities
Accrued liabilities—affiliates
Accrued interest
Accrued interest—affiliates
Deferred revenue
Deferred revenue—affiliates
Other items, net
Net cash provided by operating activities of continuing operations
Net cash provided by 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 sale of assets
Return of long-term contract receivable
Return of long-term contract receivable—affiliate
Acquisition of plant and equipment and other
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
$
$
$
$
$
73
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from financing activities
Proceeds from issuance of preferred units and warrants, net
Proceeds from issuance of 2022 Senior Notes, net
Borrowings on credit facility
Repayments of loans
Redemption of preferred units paid-in-kind
Distributions to common unitholders and general partner
Distributions to preferred unitholders
Contributions from discontinued operations
Debt issuance costs and other
Net cash used in financing activities of continuing operations
Net cash used in financing activities of discontinued operations
Net cash used in financing activities
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash of continuing operations at
beginning of period
Cash, cash equivalents and restricted cash of discontinued operations at
beginning of period
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Less: cash, cash equivalents and restricted cash of discontinued operations at
end of period
Cash, cash equivalents and restricted cash of continuing operations at end of
period
Supplemental cash flow information:
Cash paid during the period for interest from continuing operations
Non-cash investing and financing activities:
Issuance of 2022 Senior Notes in exchange for 2018 Senior Notes
Years Ended December 31,
2018
2017
2016
— $
—
35,000
(175,706)
(8,844)
(22,486)
(30,265)
195,690
(228)
(6,839) $
(196,509)
(203,348) $
$
242,100
103,688
77,000
(492,319)
—
(22,467)
(8,844)
5,784
(39,091)
(134,149) $
(7,077)
(141,226) $
—
—
20,000
(183,141)
—
(22,465)
—
52,642
(13,409)
(146,373)
(139,805)
(286,178)
176,203
$
(10,544) $
(11,402)
26,980
$
39,171
$
40,244
2,847
29,827
206,030
—
$
$
1,200
40,371
29,827
2,847
$
$
11,529
51,773
40,371
1,200
206,030
$
26,980
$
39,171
64,991
$
72,850
— $
240,638
$
$
84,380
—
$
$
$
$
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
74
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, trona, soda ash
and other natural resources and is organized into two operating segments further described in Note 8. Segment Information. As
used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners
L.P. and its subsidiaries, unless otherwise stated or indicated by context.
The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership
owns its subsidiaries through one wholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole
responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership,
its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers
of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability
company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC.
Subject to the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with
The Blackstone Group, L.P. (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. RCM has delegated the right to appoint one director to Blackstone.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally
accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the
accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with
International Paper Company controlled by the Partnership. The Partnership has an equity investment in Ciner Wyoming through
which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the
investee’s activities and is accounted for using the equity method. Intercompany transactions and balances have been eliminated.
Certain reclassifications have been made to prior year amounts on the Consolidated Statements of Comprehensive Income and
Consolidated Statements of Cash Flows to conform with current year presentation. These reclassifications have no impact on
previously reported net income or total cash flows from operating, investing or financing activities.
Recasting of Certain Prior Period Information
As described in Note 4. Discontinued Operations, the Partnership has classified the assets and liabilities, operating results
and cash flows of its construction aggregates business as discontinued operations in its consolidated financial statements for all
periods presented.
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 in 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 in the accompanying Consolidated Statements of Comprehensive Income 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 commitments and contingencies.
75
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 14. 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.
• Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value
of the assets or liabilities. Level 3 assets and liabilities include financial assets and liabilities whose value is determined
using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the
determination of fair value requires significant management judgment or estimation.
Cash, Cash Equivalents and Restricted Cash
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be
cash equivalents. Restricted cash at December 31, 2018 included cash proceeds received from the sale of the Partnership's
construction aggregates business required to be used to repay debt, make acquisitions or make capital expenditures per the terms
of its and Opco's debt agreements, as defined in Note 13. Debt, Net. NRP intends to use these proceeds to repay debt.
Allowance for Doubtful Accounts
The Partnership records an allowance for doubtful accounts for its accounts receivables and notes receivables which it
determines to be uncollectible based on the specific identification method. Receivables are written off when collection efforts are
exhausted and future recovery is doubtful. The allowance for doubtful accounts receivable is included in Accounts receivable, net
and the allowance for doubtful accounts for notes receivable is included in Other current assets on the Partnership's Consolidated
Balance Sheets, respectively. The allowance for doubtful accounts related to accounts receivable was $4.8 million at December 31,
2017. The allowance for doubtful accounts related to notes receivable included in Other current assets was $1.2 million at both
December 31, 2018 and 2017, respectively. The Partnership recorded bad debt expense of $0.1 million, $2.4 million and $0.3
million, respectively, included in Operating and maintenance expense (including affiliates) on its Consolidated Statements of
Comprehensive Income for the years ended December 31, 2018, 2017 and 2016, respectively.
Plant and Equipment
Plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the asset acquired
and consists of coal preparation plants, related coal handling facilities, and other coal and aggregates transportation and processing
infrastructure. Expenditures for new facilities or that substantially increase the useful life of property are capitalized and reported
in the Consolidated Statements of Cash Flows as an investing activity. These assets are depreciated on a straight-line basis over
their useful lives generally as follows:
Buildings and improvements
Machinery and equipment
Leasehold improvements
Mineral Rights
Years
20 to 40
5 to 12
Life of Lease
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.
76
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Intangible Assets
The Partnership’s intangible assets consist primarily of contracts that at acquisition were more favorable for the Partnership
than prevailing market rates, known as above-market contracts. Management expects for the above-market rates to be received
until the reserves are exhausted on its above-market contracts, which includes additional renewal terms of the respective leases.
The estimated fair values 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.
Asset Impairment
The Partnership has developed procedures to evaluate its long-lived assets for possible impairment periodically or whenever
events or changes in circumstances indicate an asset's carrying amount 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 assets’ carrying 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 assets’ carrying value. The Partnership
believes its estimates of cash flows and discount rates are consistent with those of principal market participants.
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.
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
they mine or sell. Most of NRP’s coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts,
either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that
generally range from three to five years.
In accordance with previous accounting standards in effect prior to January 1, 2018, NRP recognized all coal and aggregates
royalty revenue over the lease term based on production. The recognition of revenue from minimum payments was deferred until
either recoupment through royalty production occurred or when the recoupment period expired for unrecouped minimums.
Under the new revenue recognition standard, management has defined NRP's coal and aggregates royalty lease performance
obligation as providing the lessee the right to mine and sell NRP's coal or aggregates over the lease term. The Partnership then
evaluated the likelihood that consideration NRP expected to receive from its lessees resulting from production would exceed
consideration expected to be received from minimum payments over the lease term.
77
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 revenue or Aggregates royalty revenue, as applicable. Deferred revenue from minimums
is recognized as royalty revenue when recoupment occurs or as Production lease minimum revenue 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 revenue.
• 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 revenue.
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 revenue from those sales. Also, included within oil and gas royalties
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. Revenue from these interests is recognized over time based on when the coal is sold.
Wheelage. Revenue 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 revenue. Other revenue 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.
Transportation and processing services revenue. 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, forfeiture
of recoupment rights or termination due to the exhaustion of merchantable and mineable reserves. 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 modification fees within Coal
royalty and other revenues on our Consolidated Statements of Comprehensive Income while modifications in royalty rates and
minimums will be recognized prospectively in accordance with the above lease classification.
In accordance with the transition guidance in paragraph 606-10-65-1, revenues from contracts that were modified before
January 1, 2018 were not retrospectively restated for those modifications and instead reflected the aggregate effect of those
modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and
allocating the transaction price to the satisfied and unsatisfied performance obligation.
78
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 modification 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 modification 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 revenue from its production leases over the next twelve months, the Partnership is unable to estimate the current
portion of deferred revenue.
See "—Recently Adopted Accounting Standards—Revenue Recognition" below for information regarding the impact of
adopting the new revenue recognition standard in January 2018.
Equity in Earnings from 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
in 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 in the Consolidated Statements of
Comprehensive Income. The Partnership increases 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.
Property Taxes
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, in the
Consolidated Statements of Comprehensive Income.
Transportation Revenue and Expense
The Partnership records transportation revenue and pays transportation costs to a Foresight Energy LP ("Foresight Energy")
affiliate to operate equipment on behalf of the Partnership. The revenue and expenses related to these transactions are recorded as
Transportation and processing services (or Transportation and processing services—affiliates) and Operating and maintenance
expenses or (Operating and maintenance expenses—affiliates), respectively, in the Consolidated Statements of Comprehensive
Income. Subsequent to May 9, 2017, Foresight Energy is no longer deemed a related party. Refer to Note 15. Related Party
Transactions for further details.
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 expense
and Operating and maintenance expense in the Consolidated Statements of Comprehensive Income.
79
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s debt. These costs are
amortized over the term of the respective line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's
revolving credit facility are included in Other assets (long-term) 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 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
Revenue Recognition
On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers,
and all the related amendments (the “new revenue standard” and "ASC 606") to all open contracts using the modified retrospective
method. The adoption of the new revenue standard impacted royalty revenue from NRP's coal and aggregates royalty leases as
further described below. NRP recognized a $70.5 million cumulative effect of adoption adjustment in the opening balance of
partners' capital on January 1, 2018. Prior year information has not been restated and continues to be reported under the accounting
standards in effect for those periods. The new revenue standard had no impact on revenues from NRP's Soda Ash operating segment
or on the discontinued operations.
A majority of NRP’s coal and aggregates royalty revenue continues to be recognized over the lease term based on production.
For coal and aggregates royalty leases for which NRP expects consideration from minimum payments to be greater than
consideration from production over the lease term, royalty revenue is now recognized straight-line over the lease term based on
the minimum payment consideration. The cumulative effects of the changes made to the Partnership's Consolidated Balance Sheet
at January 1, 2018 for the adoption of the new revenue standard were as follows:
(In thousands)
Assets
Accounts receivable, net (including affiliates)
Liabilities
Current portion of deferred revenue
Deferred revenue
Partners’ capital
Common unitholders’ interest
General partner’s interest
Total partners’ capital
Balance at
December 31, 2017
Adjustments due to
ASC 606
Balance at
January 1, 2018
24,211
$
4,875
$
29,086
— $
100,605
1,022
(66,613)
$
199,851
1,857
265,211
69,057
1,409
70,466
$
$
1,022
33,992
268,908
3,266
335,677
$
$
$
80
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The impact of adoption of the new revenue standard on NRP’s Consolidated Balance Sheet and Consolidated Statement of
Comprehensive Income was as follows:
(In thousands)
Assets
Accounts receivable, net (including affiliates)
Total assets
Liabilities and capital
Current portion of deferred revenue
Deferred revenue
Total liabilities
Partners’ capital
Common unitholders’ interest
General partner’s interest
Total partners’ capital
Total liabilities and capital
(In thousands, except per unit data)
Coal royalty and other revenues (including affiliates) (1)
Net income from continuing operations
Net income
Net income per common unit (basic)
Net income per common unit (diluted)
As Reported
As of December 31, 2018
Balances without
Adoption of ASC 606
Effect of Change
$
$
$
$
$
$
$
32,058
1,341,647
3,509
49,044
756,514
355,113
5,014
423,481
1,341,647
27,520
1,337,109
$
4,538
4,538
— $
62,783
766,744
$
340,640
4,719
408,713
1,337,109
3,509
(13,739)
(10,230)
14,473
295
14,768
4,538
For the Year Ended December 31, 2018
As Reported
Amounts without
Adoption of ASC 606
Effect of Change
$
178,878
122,360
140,047
8.77
6.76
$
234,428
178,058
195,745
13.23
9.46
(55,550)
(55,698)
(55,698)
(4.46)
(2.70)
(1) The total effect of adopting ASC 606 was $55.6 million during the year ended December 31, 2018, which included $33.4
million related to the forfeiture of recoupable balances in connection with the fourth quarter 2018 settlement of the Macoupin
and Hillsboro lawsuits, the majority of which was previously recognized in partners' capital upon adoption and $7.2 million
of modification fees and forfeited recoupable balances related to fourth quarter 2018 lease modifications which were deferred
under ASC 606 and will be recognized straight-line over the respective modified lease terms.
Recently Issued Accounting Standards
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The new standard requires a lessee to recognize
assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more
than 12 months. This standard does not apply to leases that explore for or use minerals, oil, natural gas and similar non-regenerative
resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural
resources are contained. The guidance also requires disclosures designed to give financial statement users information on the
amount, timing and uncertainty of cash flows arising from leases. The guidance is effective for annual and interim periods beginning
after December 15, 2018 and is to be adopted using a modified retrospective approach. The Partnership will adopt this standard
effective January 1, 2019 and does not expect that the provisions of this guidance will have a material impact on its consolidated
financial statements.
81
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
3. Revenue from Contracts with Customers
Coal Royalty and Other Segment
The following table represents the Partnership's Coal Royalty and Other segment revenues (including affiliates) by major
source:
(In thousands)
Coal royalty revenue
Production lease minimum revenue
Minimum lease straight-line revenue
Property tax revenue
Wheelage revenue
Coal overriding royalty revenue
Aggregates royalty revenue
Oil and gas royalty revenue
Other revenue
Coal royalty and other revenues (1)
Transportation and processing services revenue (2)
Total Coal royalty and other segment revenues
Year Ended
December 31, 2018
$
129,341
8,207
2,362
5,422
6,484
13,878
4,739
6,608
1,837
178,878
23,887
202,765
$
$
(1) Represents revenue from contracts with customers as defined under ASC 606.
(2) Revenue from contracts with customers as defined under ASC 606 was $13.2 million for the year ended December 31, 2018.
The remaining transportation and processing services revenue of $10.7 million for the year ended December 31, 2018 was
related to other NRP-owned infrastructure leased to and operated by third party operators accounted for under ASC 840,
Leases. See Note 15. Related Party Transactions for more information on the transportation and processing services.
Contract Assets and Liabilities
The following table details the Partnership's Coal Royalty and Other segment receivables and liabilities resulting from
contracts with customers:
(In thousands)
Receivables
Total accounts receivable, net (including affiliates)(1)
Prepaid expenses and other (2)
Contract liabilities
Current portion of deferred revenue
Deferred revenue
December 31,
2018
January 1,
2018
$
$
29,001
$
2,483
3,509
$
49,044
25,443
2,830
1,022
33,992
(1)
Included in this amount is $4.4 million and $1.9 million of accounts receivable related to accrued minimum consideration
as of December 31, 2018 and January 1, 2018, respectively.
(2) Notes receivable from contracts with customers are included within Prepaid expenses and other in the Consolidated Balance
Sheets.
82
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 December 31, 2017
Cumulative adjustment for change in accounting principle (1)
Balance at January 1, 2018 (current and non-current)
Recognition of previously deferred revenue
Accrued minimum payments and lease modification fees due
Cash received for minimum payments and lease modification fees
Balance at December 31, 2018 (current and non-current) (2)
Year Ended
December 31, 2018
$
$
$
100,605
(65,591)
35,014
(20,242)
5,592
32,189
52,553
(1)
(2)
Included in this amount is $(67.5) million recognized in Partners' capital and $1.9 million of accrued minimum consideration
recognized in Accounts receivable, net.
Included in this amount is $7.2 million of deferred modification fees and forfeited recoupable balances which will be
recognized straight-line over the respective modified lease terms in Coal Royalty and other revenues on the Consolidated
Statements of Comprehensive Income over the remaining terms of the modified leases, which extend over the next 6 years.
The following table shows the Partnership's Coal Royalty and Other segment revenue recognized during the year ended
December 31, 2018 that was included in the deferred revenue balance at the beginning of the period:
(In thousands)
Production leases - revenue impact
Recoupments recognized in Coal and aggregates royalty revenue
Breakage revenue recognized in Production lease minimum revenue
Expiration of unrecouped minimums recognized in Production lease minimum revenue
Minimum leases - revenue impact
Minimum lease amortization recognized in Minimum lease straight-line revenue
Total previously deferred revenue recognized
Remaining Performance Obligations
Year Ended
December 31, 2018
$
$
10,178
7,169
935
1,960
20,242
The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty
leases are as follows:
Lease Term (1)
1 - 5 years
5 - 10 years
10+ years
Weighted Average
Remaining Years as of
December 31, 2018
Annual Minimum
Payments
(In thousands)
0.6
1.3
9.0
$
13,072
13,060
41,202
(1) The Partnership applied the practical expedient for disclosing remaining performance obligations for contracts with an
expected duration of one year or less, and have excluded those contracts from this disclosure.
The Partnership's non-cancelable annual minimum payments on its coal and aggregates royalty leases are recognized as
revenue as discussed above. In addition, the Partnership's non-cancelable annual minimum payments due under terms of its coal
and aggregates overriding royalty agreements include a $1.8 million annual minimum that expires in 2023 and a $1.0 million
minimum that expires upon exhaustion of the mineable and recoverable coal reserves, respectively.
83
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
4. Discontinued Operations
In December 2018, the Partnership sold VantaCore Partners LLC, its construction aggregates materials business for $205
million, before customary purchase price adjustments and transaction expenses, and recorded a gain of $13.1 million. The
Partnership's debt agreements require that 75% of the asset sale proceeds be used to pay down the Opco Revolving Credit Facility
(as defined in Note 13. Debt, Net) and 25% be offered to the holders of its Opco Senior Notes (as defined in Note 13. Debt, Net)
on a pro-rata basis. The outstanding balance was repaid on the Opco Revolving Credit Facility in December 2018, $49 million
was offered to the holders of the Opco Senior Notes in December 2018 and paid in January 2019 and the remaining $55 million
of net cash proceeds was restricted as of December 31, 2018. NRP intends to use these remaining proceeds to repay its Opco Senior
Notes as they amortize in 2019.
In July 2016, NRP Oil and Gas LLC ("NRP Oil and Gas") sold its non-operated oil and gas working interest assets for $116.1
million in gross sales proceeds. The sale had an effective date of April 1, 2016.
The Partnership's exit from both its construction aggregates materials 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 in its Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income and Consolidated Statements
of Cash Flows for all periods presented.
The following tables present the carrying amounts of the Partnership's assets and liabilities of discontinued operations in the
Consolidated Balance Sheets:
(In thousands)
Current assets:
Accounts receivable, net
ASSETS
Total assets of discontinued operations
LIABILITIES
Current liabilities:
Accounts payable (including affiliates)
Accrued liabilities
Total liabilities of discontinued operations
December 31, 2018
Construction
Aggregates
NRP
Oil and Gas
Total
$
$
$
$
5
5
181
766
947
$
$
$
$
988
988
$
$
— $
—
— $
993
993
181
766
947
84
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(In thousands)
Current assets:
ASSETS
Cash and cash equivalents
Accounts receivable, net
Inventory
Prepaid expenses and other
Total current assets of discontinued operations
Land
Plant and equipment, net
Mineral rights, net
Intangible assets, net
Other assets
Total assets of discontinued operations
LIABILITIES
Current liabilities:
Accounts payable (including affiliates)(1)
Accrued liabilities
Other
Total current liabilities of discontinued operations
Other non-current liabilities
Total liabilities of discontinued operations
December 31, 2017
Construction
Aggregates
NRP
Oil and Gas
Total
$
2,847
$
— $
22,976
7,553
2,056
35,432
1,239
44,822
105,466
2,734
1,681
991
—
—
991
—
—
—
—
—
2,847
23,967
7,553
2,056
36,423
1,239
44,822
105,466
2,734
1,681
$
$
$
191,374
$
991
$
192,365
6,019
$
— $
5,348
—
11,367
2,220
—
401
401
—
13,587
$
401
$
6,019
5,348
401
11,768
2,220
13,988
(1) See Note 15. Related Party Transactions for additional information on the Partnership's related party liabilities.
85
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following tables present summarized financial results of the Partnership's discontinued operations in the Consolidated
Statements of Comprehensive Income:
(In thousands)
Revenues and other income:
Construction aggregates
Road construction and asphalt paving services
Oil and gas
Gain on asset sales, net
Total revenues and other income
Operating expenses:
Operating and maintenance expenses (including affiliates)(1)
Depreciation, depletion and amortization
Asset impairments
Total operating expenses
Interest expense, net
Income (loss) from discontinued operations
For the Year Ended December 31, 2018
Construction
Aggregates
NRP
Oil and Gas
Total
$
$
$
$
$
$
116,066
18,400
—
13,414
147,880
$
— $
—
(3)
—
(3) $
117,568
$
134
$
12,218
232
—
—
116,066
18,400
(3)
13,414
147,877
117,702
12,218
232
130,018
$
134
$
130,152
(38)
17,824
$
—
(137) $
(38)
17,687
(1) See Note 15. Related Party Transactions for additional information on the Partnership's related party expenses.
(In thousands)
Revenues and other income:
Construction aggregates
Road construction and asphalt paving services
Oil and gas
Gain (loss) on asset sales
Total revenues and other income
Operating expenses:
Operating and maintenance expenses (including affiliates)(1)
Depreciation, depletion and amortization
Asset impairments
Total operating expenses
Interest expense, net
Income (loss) from discontinued operations
For the Year Ended December 31, 2017
Construction
Aggregates
NRP
Oil and Gas
Total
$
$
$
$
$
112,970
$
18,411
—
311
131,692
$
$
111,633
12,579
64
— $
—
38
(289)
(251) $
290
$
—
—
112,970
18,411
38
22
131,441
111,923
12,579
64
124,276
$
290
$
124,566
(693)
6,723
$
—
(541) $
(693)
6,182
(1) See Note 15. Related Party Transactions for additional information on the Partnership's related party expenses.
86
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, net
Total revenues and other income
Operating expenses:
Operating and maintenance expenses (including affiliates)(1)
Depreciation, depletion and amortization
Asset impairments
Total operating expenses
Interest expense, net
Income from discontinued operations
For the Year Ended December 31, 2016
Construction
Aggregates
NRP Oil and Gas
Total
$
$
$
$
$
103,755
$
17,047
—
13
— $
—
16,486
8,274
103,755
17,047
16,486
8,287
120,815
$
24,760
$
145,575
100,656
$
11,503
$
14,506
1,065
116,227
$
—
4,588
$
7,527
564
19,594
(3,488)
1,678
$
$
112,159
22,033
1,629
135,821
(3,488)
6,266
(1) See Note 15. Related Party Transactions for additional information on the Partnership's related party expenses.
The following table presents supplemental cash flow information of the Partnership's discontinued operations:
(In thousands)
Cash paid for interest
Year Ended December 31,
2018
2017
2016
$
— $
— $
1,906
Plant, equipment and mineral rights funded with accounts payable or
accrued liabilities
881
294
—
Capital expenditures related to the Partnership's discontinued operations were $10.9 million, $7.6 million and $6.7 million
during the years ended December 31, 2018, 2017 and 2016, respectively.
5. Class A Convertible Preferred Units and Warrants
On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in
NRP (the "Preferred Units") to certain entities controlled by funds affiliated with The Blackstone Group, L.P. (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% 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.
87
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
After March 2, 2022 and prior to March 2, 2025, the holders of the Preferred Units may elect to convert up to 33% of the
outstanding Preferred Units in any 12-month period into common units if the volume weighted average trading price of our common
units (the "VWAP") for the 30 trading days immediately prior to date notice is provided is greater than $51.00. In such case, the
number of common units to be issued upon conversion would be equal to the Per Unit Purchase Price plus the value of any accrued
and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior
to the notice of conversion. Rather than have the Preferred Units convert to common units in accordance with the provisions of
this paragraph, NRP would have the option to elect to redeem the Preferred Units proposed to be converted for cash at a price
equal to Per Unit Purchase Price plus the value of any accrued and unpaid distributions.
On or after March 2, 2025, the holders of the Preferred Units may elect to convert the Preferred Units to common units at a
conversion rate equal to the Liquidation Value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days
immediately prior to the notice of conversion. The “Liquidation Value” will be an amount equal to the greater of: (1) (a) the Per
Unit Purchase Price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021, 1.70
and (iii) on or after March 2, 2021, 1.85, less (b)(i) all Preferred Unit distributions previously made by NRP and (ii) all cash
payments previously made in respect of redemption of any PIK Units; and (2) the Per Unit Purchase Price plus the value of all
accrued and unpaid distributions.
To the extent the holders of the Preferred Units have not elected to convert their Preferred Units 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
of GP Natural Resource Partners LLC.
88
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NRP also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with
the Preferred Purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units
issuable upon exercise of the Warrants and to cause such registration statement to become effective not later than 90 days following
the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the Preferred Units
and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date
or 90 days following the first issuance of any common units upon conversion of Preferred Units (the "Registration Deadlines").
In addition, the Preferred Unit and Warrant Registration Rights Agreement gives the Preferred Purchasers piggyback registration
and demand underwritten offering rights under certain circumstances. The shelf registration statement to register the common units
issuable upon exercise of the Warrants became effective on April 20, 2017. If the shelf registration statement to register the common
units issuable upon conversion of the Preferred Units is not effective by the applicable Registration Deadline, NRP will be required
to pay the Preferred Purchasers liquidated damages in the amounts and upon the term set forth in the Preferred Unit and Warrant
Registration Rights Agreement.
Accounting for the Preferred Units and Warrants
Classification
The Preferred Units are accounted for on NRP's consolidated balance sheets as temporary equity due to certain contingent
redemption rights that may be exercised at the election of Preferred Purchasers. The Warrants are accounted for on NRP's
consolidated balance sheets as equity.
Initial Measurement
The net transaction price as shown below was allocated to the Preferred Units and Warrants based on their relative fair values
at inception date. NRP allocated the transaction issuance costs to the Preferred Units and Warrants primarily on a pro-rata basis
based on their relative inception date allocated values. The Preferred Units and Warrants were initially recognized as follows:
(In thousands)
Transaction price, gross
Structuring, origination and other fees to Preferred Purchasers
Transaction costs to other third parties
Transaction price, net
Allocation of net transaction price
Preferred Units, net
Warrant holders interest, net
Transaction price, net
March 2, 2017
250,000
(7,900)
(10,697)
231,403
164,587
66,816
231,403
$
$
$
$
89
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Subsequent Measurement
Subsequent adjustment of the Preferred Units will not occur until NRP has determined that the conversion or redemption of
all or a portion of the Preferred Units is probable of occurring. Once conversion or redemption becomes probable of occurring,
the carrying amount of the Preferred Units will be accreted to their redemption value over the period from the date the feature is
probable of occurring to the date the Preferred Units can first be converted or redeemed.
During the three months ended March 31, 2018, the Partnership redeemed all of the outstanding PIK Units, which resulted
in an $8.8 million cash payment during the period.
Activity related to the Preferred Units is as follows:
(In thousands, except unit data)
Balance at December 31, 2016
Issuance of Preferred Units, net
Distribution paid-in-kind
Balance at December 31, 2017
Redemption of PIK Units
Balance at December 31, 2018
Units
Outstanding
Financial Position
— $
250,000
8,844
258,844
(8,844)
250,000
$
$
—
164,587
8,844
173,431
(8,844)
164,587
Subsequent adjustment of the Warrants will not occur until the Warrants are exercised, at which time, NRP may, at its option,
elect to settle the Warrants in common units or cash, each on a net basis. The net basis will be equal to the difference between the
Partnership's common unit price and the strike price of the Warrant. Once Warrant exercise occurs, the difference between the
carrying amount of the Warrants and the net settlement amount will be allocated on a pro-rata basis to the common unitholders
and general partner.
Certain embedded features within the Preferred Unit and Warrant purchase agreement are accounted for at fair value and are
remeasured each quarter. See Note 14. Fair Value Measurements for further information regarding valuation of these embedded
derivatives.
90
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
6. Common and Preferred Unit Distributions
The Partnership makes cash distributions to common unit holders on a quarterly basis, subject to approval by the Board of
Directors. As discussed in Note 5. Class A Convertible Preferred Units and Warrants above, the Partnership also makes distributions
to the preferred unitholders. NRP recognizes both Common and Preferred Unit distributions on the date the distribution is declared.
Common Unit Distributions
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. The following table shows the distributions declared and paid to common unitholders during the years ended December
31, 2018, 2017 and 2016, respectively:
Date Paid
Period Covered by Distribution
Distribution per
Common Unit
Common Units
GP Interest
Total
Total Distributions (in thousands)
2018
February 14, 2018
October 1 - December 31, 2017
$
May 14, 2018
August 14, 2018
January 1 - March 31, 2018
April 1 - June 30, 2018
November 14, 2018
July 1 - September 30, 2018
2017
February 14, 2017
October 1 - December 31, 2016
$
May 12, 2017
August 14, 2017
January 1 - March 31, 2017
April 1 - June 30, 2017
November 14, 2017
July 1 - September 30, 2017
2016
February 12, 2016
October 1 - December 31, 2015
$
May 13, 2016
August 12, 2016
January 1 - March 31, 2016
April 1 - June 30, 2016
November 14, 2016
July 1 - September 30, 2016
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
0.45
$
5,505
$
5,510
5,511
5,510
$
5,503
$
5,506
5,504
5,505
$
5,503
$
5,503
5,505
5,503
$
$
$
112
113
112
113
112
113
112
112
113
113
112
113
5,617
5,623
5,623
5,623
5,615
5,619
5,616
5,617
5,616
5,616
5,617
5,616
91
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Preferred Unit Distributions
The following table shows the distributions declared and paid to Preferred Unitholders during the years ended December 31,
2018 and 2017:
Date Paid
Period Covered by Distribution
2018
February 7, 2018
May 14, 2018
August 14, 2018
October 1 - December 31, 2017
January 1 - March 31, 2018
April 1 - June 30, 2018
November 14, 2018
July 1 - September 30, 2018
2017
May 30, 2017
August 29, 2017
March 2 - March 31, 2017
April 1 - June 30, 2017
November 29, 2017
July 1 - September 30, 2017
Distribution
per Preferred
Unit
Total
Distribution
Declared
(in thousands)
$
30.00
$
30.00
30.00
30.00
$
5.00
$
15.00
15.00
7,765
7,500
7,500
7,500
2,500
7,538
7,650
Income available to common unitholders and the general partner is reduced by Preferred Unit distributions that accumulated
during the period. During the year ended December 31, 2018 and 2017, NRP reduced net income attributable to common unitholders
and the general partner by $30.0 million and $25.5 million, respectively as a result of accumulated Preferred Unit distributions
earned during the period. The $7.5 million preferred unit distribution earned during the three months ended December 31, 2018
was paid on February 14, 2019.
7. Net Income Per Common Unit
Basic net income per common unit is computed by dividing net income, 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 per common unit includes the effect of NRP's Preferred Units and Warrants, 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 per unit calculation for the period being presented. Distributions declared in the period and
undeclared distributions on the Preferred Units that accumulated during the period are added back to the numerator for purposes
of the if-converted calculation.
The 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. The calculation of the
dilutive effect of the Warrants for the years ended December 31, 2018 and 2017 includes 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.
92
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table reconciles the numerators and denominators of the basic and diluted net income per common unit
computations and calculates basic and diluted net income per common unit:
(In thousands, except per unit data)
Allocation of net income:
Net income from continuing operations
Less: net income attributable to non-controlling interest
Less: income attributable to preferred unitholders
Net income from continuing operations attributable to common unitholders and
general partner
Less: net income from continuing operations attributable to the general
partner
Net income 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
Less: net income attributable to non-controlling interest
Less: income attributable to preferred unitholders
Net income attributable to common unitholders and general partner
Less: net income attributable to the general partner
Net income attributable to common unitholders
Basic income per common unit:
Weighted average common units—basic
Basic net income from continuing operations per common unit
Basic net income from discontinued operations per common unit
Basic net income per common unit
Year Ended December 31,
2018
2017
2016
$
122,360
$
82,485
$
90,626
(510)
(30,000)
—
(25,453)
—
—
$
$
$
$
$
$
$
$
$
$
91,850
$
57,032
$
90,626
(1,837)
(1,141)
(1,537)
90,013
17,687
(354)
17,333
140,047
(510)
(30,000)
109,537
(2,191)
107,346
12,244
7.35
1.42
8.77
$
$
$
$
$
$
$
$
$
55,891
6,182
(123)
6,059
88,667
—
(25,453)
63,214
(1,264)
61,950
12,232
4.57
0.50
5.06
$
$
$
$
$
$
$
$
$
89,089
6,266
(126)
6,140
96,892
—
—
96,892
(1,663)
95,229
12,232
7.28
0.50
7.78
93
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(In thousands, except per unit data)
Diluted income per common unit:
Weighted average common units—basic
Plus: dilutive effect of Warrants
Plus: dilutive effect of Preferred Units
Weighted average common units—diluted
Net income from continuing operations
Less: net income attributable to non-controlling interest
Diluted net income from continuing operations attributable to common
unitholders and general partner
Less: net income from continuing operations attributable to the general
partner
Diluted net income from continuing operations attributable to common
unitholders
Diluted net income from discontinued operations attributable to common unitholders
Net income
Less: net income attributable to non-controlling interest
Diluted net income attributable to common unitholders and general partner
Less: diluted net income attributable to the general partner
Diluted net income attributable to common unitholders
Diluted net income from continuing operations per common unit
Diluted net income from discontinued operations per common unit
Diluted net income per common unit
Year Ended December 31,
2018
2017
2016
12,244
511
7,479
20,234
12,232
300
9,418
21,950
12,232
—
—
12,232
122,360
$
82,485
$
90,626
(510)
—
—
121,850
$
82,485
$
90,626
(2,437)
(1,650)
(1,537)
119,413
17,333
140,047
(510)
139,537
(2,791)
136,746
5.90
0.86
6.76
$
$
$
$
$
$
$
$
80,835
6,059
88,667
—
88,667
(1,773)
86,894
3.68
0.28
3.96
$
$
$
$
$
$
$
$
89,089
6,140
96,892
—
96,892
(1,663)
95,229
7.28
0.50
7.78
$
$
$
$
$
$
$
$
$
$
94
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
8. Segment Information
The Partnership's segments are strategic business units that offer distinct products and services to different customers in
different geographies within the U.S. and that are managed accordingly. NRP has the following two operating segments:
Coal Royalty and Other—consists primarily of coal royalty and coal-related transportation and processing assets. Other
assets include industrial minerals 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 aggregates and industrial minerals properties are located in a number of states across the United
States. The Partnership's oil and gas royalty assets are primarily located in Louisiana.
Soda Ash—consists of the Partnership's 49% non-controlling equity interest in Ciner Wyoming, a trona ore mining operation
and soda ash refinery in the Green River Basin of Wyoming. Ciner Resources LP, the Partnership's operating partner, mines the
trona, processes it into soda ash, and distributes the soda ash both domestically and internationally to the glass and chemicals
industries.
In December 2018, the Partnership sold its construction aggregates business for $205 million, before customary purchase
price adjustments and transaction expenses, and recorded a gain of $13.1 million. The Partnership's exit from the construction
aggregates business enabled it to further reduce debt, focus on its Coal Royalty and Other and Soda Ash business segments and
represented a strategic shift as it exited the operations of its construction aggregates business. The gain on sale and operating results
of the construction aggregates business is included in Income from discontinued operations on the Consolidated Statements of
Comprehensive Income and the net cash proceeds received is included in Cash provided by investing activities of discontinued
operations in the Partnership's Consolidated Statements of Cash Flows for the year ended December 31, 2018. See Note 4.
Discontinued Operations for more information.
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 insurance, taxes, legal,
information technology and shared facilities services and are included in Operating and maintenance expenses and Operating and
maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income.
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 and accounting and other
corporate-level activity not specifically allocated to a segment and are included in General and administrative expenses and General
and administrative expenses—affiliates on the Consolidated Statements of Comprehensive Income.
95
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, 2018
Revenues (including affiliates)
Gain on litigation settlement
Gain on asset sales, net
Operating and maintenance expenses
(including affiliates)
Depreciation, depletion and amortization
General and administrative (including affiliates)
Asset impairments
Other expense, net
Net income (loss) from continuing operations
Net income from discontinued operations
As of December 31, 2018
Total assets of continuing operations
Total assets of discontinued operations
For the Year Ended December 31, 2017
Revenues (including affiliates)
Gain on asset sales, net
Operating and maintenance expenses
(including affiliates)
Depreciation, depletion and amortization
(including affiliates)
General and administrative (including affiliates)
Asset impairments
Other expense, net
Net income (loss) from continuing operations
Net income from discontinued operations
As of December 31, 2017
Total assets of continuing operations
Total assets of discontinued operations
For the Year Ended December 31, 2016
Revenues (including affiliates)
Gain on asset sales, net
Operating and maintenance expenses
(including affiliates)
Depreciation, depletion and amortization
(including affiliates)
General and administrative (including affiliates)
Asset impairments
Other expense, net
Net income (loss) from continuing operations
Net income from discontinued operations
Capital expenditures
Operating Segments
Coal Royalty
and Other
Soda Ash
Corporate
and
Financing
Total
$
$ 202,765
25,000
2,441
29,509
21,689
—
18,280
—
160,728
—
48,306
—
—
—
—
—
—
—
48,306
—
$
— $ 251,071
25,000
—
2,441
—
—
—
16,496
—
70,178
(86,674)
—
29,509
21,689
16,496
18,280
70,178
122,360
17,687
$ 986,680
—
$ 247,051
—
$ 106,923
—
$1,340,654
993
$ 202,323
3,545
$
$
40,457
—
— $ 242,780
3,545
—
24,883
—
—
24,883
23,414
—
2,967
—
154,604
—
—
—
—
—
40,457
—
—
18,502
—
94,074
(112,576)
—
23,414
18,502
2,967
94,074
82,485
6,182
$ 945,237
—
$ 245,433
—
$ 210,115
29,068
$
40,061
—
$
$
6,129
—
$1,196,799
192,365
— $ 250,176
29,068
—
29,890
—
—
29,890
31,766
—
15,861
—
161,666
—
5
—
—
—
—
40,061
—
—
—
20,570
—
90,531
(111,101)
—
—
31,766
20,570
15,861
90,531
90,626
6,266
5
96
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9. Equity Investment
The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Activity related
to this investment is as follows:
(In thousands)
Balance at beginning of period
Income allocation to NRP’s equity interests(1)
Amortization of basis difference
Comprehensive income (loss) from unconsolidated investment
Distribution
Balance at end of period
For the Year Ended December 31,
2018
2017
2016
$
245,433
$
255,901
$
261,942
53,095
(4,789)
(138)
(46,550)
247,051
$
44,846
(4,389)
(1,925)
(49,000)
245,433
$
44,882
(4,821)
448
(46,550)
255,901
$
(1)
Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $0.5
million, $0.7 million and $0.9 million for the year ended December 31, 2018, 2017 and 2016, 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 $140.8 million and $145.6 million as of December 31, 2018 and 2017, respectively. This
excess basis relates to property, plant and equipment and right to mine assets. The excess basis difference that relates to property,
plant and equipment is being amortized into income using the straight-line method over 28 years. The excess basis difference that
relates to right to mine assets is being amortized into income using the units of production method.
The following table represents summarized financial information for Ciner Wyoming as derived from the respective financial
statements for the years ended December 31, 2018, 2017, and 2016:
(In thousands)
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,
2018
2017
2016
$
486,759
$
497,340
$
104,053
108,357
114,202
91,523
475,187
114,232
91,596
December 31,
2018
2017
$
138,080
$
252,743
64,012
109,921
180,433
228,002
56,219
148,401
97
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
10. Plant and Equipment, Net
The Partnership’s plant and equipment consist of the following:
(In thousands)
Plant and equipment at cost
Less: accumulated depreciation
Total plant and equipment, net
December 31,
2018
2017
$
$
6,865
(5,881)
984
$
$
6,865
(5,517)
1,348
Depreciation expense included in Depreciation, depletion and amortization on the Partnership's Consolidated Statements of
Comprehensive Income totaled $0.4 million, $0.4 million and $0.8 million for the year ended December 31, 2018, 2017 and 2016,
respectively.
Impairment expense related to the Partnership's plant and equipment included in Asset impairments on the Consolidated
Statements of Comprehensive Income totaled $2.0 million for the year ended December 31, 2016.
11. Mineral Rights, Net
The Partnership’s mineral rights consist of the following:
(In thousands)
Coal properties
Aggregates properties
Oil and gas royalty properties
Other
Total mineral rights, net
(In thousands)
Coal properties
Aggregates properties
Oil and gas royalty properties
Other
Total mineral rights, net
December 31, 2018
Accumulated
Depletion
Carrying Value
Net Book Value
$ 1,164,845
$
24,920
12,395
13,158
$ 1,215,318
$
(451,210) $
(11,814)
(7,632)
(1,550)
(472,206) $
713,635
13,106
4,763
11,608
743,112
December 31, 2017
Accumulated
Depletion
Carrying Value
Net Book Value
$ 1,170,104
$
37,942
12,395
13,168
$ 1,233,609
$
(436,964) $
(9,602)
(7,158)
(1,466)
(455,190) $
733,140
28,340
5,237
11,702
778,419
Depletion expense related to the Partnership’s mineral rights is included in Depreciation, depletion and amortization on the
Partnership's Consolidated Statements of Comprehensive Income and totaled $17.0 million, $20.1 million and $27.8 million for
the year ended December 31, 2018, 2017 and 2016, respectively.
Sales of Mineral Rights
During the year ended December 31, 2018, the Partnership sold mineral reserves in its Coal Royalty and Other segment in
multiple transactions for cumulative gross proceeds of $2.4 million and recorded a cumulative gain of $2.4 million included in
Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
During the year ended December 31, 2017, the Partnership sold mineral reserves in its Coal Royalty and Other segment in
multiple transactions for cumulative gross proceeds of $1.0 million and recorded a cumulative gain of $3.5 million included in
Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
98
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the year ended December 31, 2016, the Partnership sold the following assets:
1) Oil and gas royalty and overriding royalty interests in the Coal Royalty and Other segment in several producing properties
located in the Appalachian Basin for $36.4 million gross sales proceeds. The effective date of the sale was January 1, 2016, and
the Partnership recorded an $18.6 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of
Comprehensive Income.
2) Aggregates reserves and related royalty rights in the Coal Royalty and Other segment at three aggregates operations
located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds. The effective date of the sale was February 1,
2016, and the Partnership recorded a $1.5 million gain from this sale included in Gain on asset sales, net on its Consolidated
Statement of Comprehensive Income.
In addition to the two asset sales described above, during the year ended December 31, 2016, the Partnership sold mineral
reserves within its Coal Royalty and Other segment in multiple sale transactions for $17.3 million of cumulative gross sales
proceeds and recorded a cumulative gain of $8.6 million from these sale transactions that are included in Gain on asset sales, net
on its Consolidated Statement of Comprehensive Income. These amounts primarily relate to eminent domain transactions with
governmental agencies and the sale of additional oil and gas royalty interests.
Impairment of Mineral Rights
During the years ended December 31, 2018, 2017 and 2016, 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 as follows:
(In thousands)
Coal properties (1)
Oil and gas properties
Aggregates and timber royalty properties (2)
Total
For the Years Ended December 31,
2018
2017
2016
$
$
5,259
$
595
$
12,088
—
13,021
—
2,372
18,280
$
2,967
$
36
1,677
13,801
(1) The Partnership recorded $5.3 million of coal property impairments during the year ended December 31, 2018 primarily as
a result of lease terminations, of which it recorded $5.0 million of impairment expense to fully impair certain coal properties
during the three months ended December 31, 2018. The Partnership recorded $0.6 million of coal property impairments
during the year ended December 31, 2017. The Partnership recorded $12.1 million of coal property impairments during the
year ended December 31, 2016 primarily as a result of lease surrender and termination. The Partnership recorded $3.8 million
of coal property impairment during the three months ended September 30, 2016 and the fair value of the impaired asset was
reduced to $4.0 million at September 30, 2016. The Partnership recorded $8.2 million of impairment expense to fully impair
certain coal property impairment during the three months ended December 31, 2016.
(2) 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.
The Partnership recorded $2.4 million and $1.7 million of aggregates and timber royalty properties impairments during the
year ended December 31, 2017 and 2016, respectively.
99
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
12. Intangible Assets, Net
The Partnership's intangible assets consist of above-market coal and related transportation contracts with subsidiaries of
Foresight Energy in which the Partnership receives throughput fees for the handling and transportation of coal. The Partnership's
intangible assets included on its Consolidated Balance Sheets are as follows:
(In thousands)
Intangible assets
Less: accumulated amortization
Total intangible assets, net
December 31,
2018
2017
$
$
81,109
(38,596)
42,513
$
$
81,109
(34,289)
46,820
Amortization expense included in Depreciation, depletion and amortization on the Partnership's Consolidated Statements
of Comprehensive Income was $4.3 million and $2.0 million for the years ended December 31, 2018 and 2017, respectively.
Amortization expense included in Amortization expense—affiliates on the Partnership's Consolidated statements of Comprehensive
income was $1.0 million and $3.2 million for the years ended December 31, 2017 and 2016, respectively. As of May 9, 2017,
Foresight Energy was no longer deemed to be an affiliate of the Partnership. Refer to Note 15. Related Party Transactions for
additional details.
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)
2019
2020
2021
2022
2023
The weighted average remaining amortization period for contract intangibles was 16 years.
$
Estimated
Amortization
Expense
3,251
3,741
3,660
3,636
3,602
100
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
13. Debt, Net
The Partnership's debt consists of the following:
(In thousands)
NRP LP debt:
December 31,
2018
2017
10.500% senior notes, with semi-annual interest payments in March and September,
due March 2022, $241 million issued at par and $105 million issued at 98.75%
$
345,638
$
345,638
Opco debt:
Revolving credit facility
Senior notes
4.91% with semi-annual interest payments in June and December, with annual
principal payments in June, due June 2018
8.38% with semi-annual interest payments in March and September, with annual
principal payments in March, due March 2019
5.05% with semi-annual interest payments in January and July, with annual
principal payments in July, due July 2020
5.55% with semi-annual interest payments in June and December, with annual
principal payments in June, due June 2023
4.73% with semi-annual interest payments in June and December, with annual
principal payments in December, due December 2023
5.82% with semi-annual interest payments in March and September, with annual
principal payments in March, due March 2024
8.92% with semi-annual interest payments in March and September, with annual
principal payments in March, due March 2024
5.03% with semi-annual interest payments in June and December, with annual
principal payments in December, due December 2026
5.18% with semi-annual interest payments in June and December, with annual
principal payments in December, due December 2026
Total debt at face value
Net unamortized debt discount
Net unamortized debt issuance costs
Total debt, net
Less: current portion of long-term debt
Total long-term debt, net
NRP LP Debt
2022 Senior Notes
—
—
21,319
15,290
13,414
37,195
89,529
27,185
60,000
4,586
42,670
22,946
16,115
44,693
104,520
31,733
107,013
120,547
30,555
687,138
(1,266)
(13,114)
672,758
115,184
557,574
$
$
$
34,396
827,844
(1,661)
(16,835)
809,348
79,740
729,608
$
$
$
In March 2017, NRP and NRP Finance issued $346 million aggregate principal amount of 2022 Senior Notes to several
holders of their 2018 Senior Notes. Of the $346 million of 2022 Senior Notes issued, $241 million in aggregate principal amount
were issued in exchange for $241 million in aggregate principal amount of 2018 Senior Notes, and $105 million of the 2022 Senior
Notes were issued to the holders for cash. The 2022 Senior Notes are issued under an Indenture dated as of March 2, 2017 (the
"Indenture"), bear interest at 10.500% per year, are payable semi-annually on March 15 and September 15, beginning September
15, 2017, and mature on March 15, 2022. The $105.0 million in 2022 Senior Notes purchased for cash were issued at a price of
98.75% (original issue discount of 1.25%), and each holder exchanging 2018 Senior Notes received a fee of 5.813% of the aggregate
principal amount of all 2018 Senior Notes tendered for exchange by such holder, as well as all accrued and unpaid interest thereon.
The 5.813% fee included a 4.563% call premium on the early repayment of the 2018 Senior Notes and a 1.25% fee on the exchange
of the 2018 Notes for 2022 Senior Notes. This fee is accounted for as a debt issuance cost, capitalized and shown net of the debt
liability on the Partnership's Consolidated Balance Sheets.
101
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NRP and NRP Finance have the option to redeem the 2022 Senior Notes, in whole or in part, at any time on or after March
15, 2019, at the redemption prices (expressed as percentages of principal amount) of 105.25% for the 12-month period beginning
March 15, 2019, 102.625% for the 12-month period beginning March 15, 2020, and thereafter at 100.000%, together, in each case,
with any accrued and unpaid interest to the date of redemption. Furthermore, before March 15, 2019, NRP may on any one or
more occasions redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes with the net proceeds of certain
public or private equity offerings at a redemption price of 110.500% of the principal amount of 2022 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 2022 Senior Notes
issued under the 2022 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 2022 Indenture, the holders
of the 2022 Senior Notes may require the Partnership to purchase their 2022 Senior Notes at a purchase price equal to 101% of
the principal amount of the 2022 Senior Notes, plus accrued and unpaid interest, if any.
The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing
the 2018 Senior Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under
the debt incurrence covenant, NRP's non-guarantor restricted subsidiaries will not be permitted to incur additional indebtedness
unless their consolidated leverage ratio is less than 3.00x (measured on a pro forma basis and assuming that the greater of (i) $150.0
million of debt (or, if less, at NRP's election, the amount of total lending commitments under any revolving credit facility) and (ii)
the actual amount of debt outstanding is outstanding under any revolving credit facility); provided, however, that such non-guarantor
restricted subsidiaries will be permitted to make up to $150 million in borrowings under a revolving credit facility (which amount
will be reduced on a dollar-for-dollar basis to the extent NRP has made the election described in clause (i) above). Under the
restricted payments covenant, NRP will not be able to increase the quarterly distribution on its common units or elect to pay more
than 50% of the distributions required to be made on the Preferred Units in cash, unless, in each case, its consolidated leverage
ratio is less than 4.00x. The 2022 Indenture also contains restrictions on NRP's ability to redeem the Preferred Units.
The 2022 Senior Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 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 2022 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, as defined below. None of NRP's subsidiaries guarantee the 2022 Senior Notes.
As of December 31, 2018 and December 31, 2017, NRP and NRP Finance were in compliance with the terms of their debt
agreements.
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, 2018 and 2017, Opco was in compliance with the
terms of the financial covenants contained in its debt agreements.
Opco Credit Facility
Opco’s Third Amended and Restated Credit Agreement, as amended (the "Opco Credit Facility"), matures on April 30, 2020.
As of December 31, 2018, Opco had $100 million in available borrowing capacity under the Opco Credit Facility. As discussed
in Note 4. Discontinued Operations, in December 2018 the Partnership repaid the outstanding balance of the Opco Credit Facility
as a result of the sale of its construction aggregates business.
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%.
102
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for the years ended
December 31, 2018 and 2017 were 6.23% and 5.32%, respectively. Debt issuance costs related to the OpCo credit facility were
$1.7 million and $4.6 million at December 31, 2018 and 2017, respectively and have been capitalized and included in Other assets
on the Partnership's Consolidated Balance Sheets. 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 NRP 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 $548.9
million and $553.9 million classified as Plant and equipment and Mineral rights as of December 31, 2018 and 2017, respectively,
and $95.7 million included in Long-term assets of discontinued operations on the Partnership’s Consolidated Balance Sheets as
of December 31, 2017. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP
Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned
by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties,
and (4) certain of Opco’s coal-related infrastructure assets.
Opco Senior Notes
Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and
principal due dates. As of December 31, 2018 and 2017, the Opco Senior Notes had cumulative principal balances of $341.5
million and $422.2 million, respectively. Opco made mandatory principal payments on the Opco Senior Notes of $80.7 million,
$80.8 million and $82.9 million for the years ended December 31, 2018, 2017 and 2016, respectively. As discussed in Note 4.
Discontinued Operations, as a result of the sale of the Partnership's construction aggregates business, $49 million was offered to
the holders of the Opco Senior Notes and paid during the first quarter of 2019. The remaining $55 million of net cash proceeds
from the sale of the construction aggregates business is restricted and the Partnership intends to use these remaining proceeds to
repay its Opco Senior Notes as they amortize in 2019.
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.
103
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The 8.38% and 8.92% Opco Senior Notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness
to consolidated EBITDDA (as defined in the Note Purchase Agreements) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then
in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the
notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. Opco has not
exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2018.
In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale
proceeds to make mandatory prepayment offers on the Opco Senior Notes as follows:
•
•
until the earlier of the time that (1) Opco has sold $300 million of assets and (2) June 30, 2020, Opco will be required
to make prepayment offers to the holders of the Opco Senior Notes using 25% of the net cash proceeds from certain
asset sales; and
after the earlier to occur of the dates above, Opco will be required to make prepayment offers to the holders of the Opco
Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the
amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being
prepaid.
The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior
Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the
Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do
not affect the maturity dates of any series of the Opco Senior Notes.
Consolidated Principal Payments
The consolidated principal payments due are set forth below:
(In thousands)
2019
2020
2021
2022
2023
Thereafter
NRP LP
Senior Notes (1)
Opco
Senior Notes
Credit Facility
Total
$
— $
116,125
$
— $
116,125
—
—
345,638
—
—
46,436
39,634
39,634
39,634
60,037
—
—
—
—
—
46,436
39,634
385,272
39,634
60,037
$
345,638
$
341,500
$
— $
687,138
(1) The 10.500% senior notes due 2022 were issued at a discount and were carried at $344.4 million and $344.0 million as of
December 31, 2018 and 2017, respectively.
104
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
14. Fair Value Measurements
Fair Value of Financial Assets and Liabilities
The Partnership’s financial assets and liabilities consist of cash and cash equivalents, restricted cash, contracts receivable,
debt, Preferred Units and Warrants. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents
and restricted cash approximate fair value due to their short-term nature. There were no transfers between Level 1, Level 2 or
Level 3 of the fair value hierarchy during the years ended December 31, 2018 or 2017.
The Partnership uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of
debt is the estimated amount the Partnership would have to pay a third party to assume the debt, including a credit spread for the
difference between the issue rate and the period end market rate. The credit spread is the Partnership's default or repayment risk.
The following table shows the carrying amount and estimated fair value of the Partnership's debt and contracts receivable:
(In thousands)
Debt:
NRP 2022 Senior Notes (1)
Opco Senior Notes (2)
Opco Revolving Credit Facility (3)
December 31, 2018
December 31, 2017
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
$
334,024
$
356,871
$
330,404
$
338,734
352,599
—
—
418,944
60,000
366,376
447,538
60,000
Assets:
Contracts receivable, current and long-term (4)
$
40,776
$
34,704
$
43,826
$
30,517
(1) The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period
end.
(2) Due to no observable quoted prices on these instruments, the Level 3 fair value is estimated by management using quotations
obtained for the NRP Senior Notes on the closing trading prices near period end.
(3) The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective
of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.
(4) The Level 3 fair value is determined based on the present value of future cash flow projections related to the underlying
assets.
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 expense, net in the Partnership's Consolidated Statements of Comprehensive Income. The embedded derivatives
had zero value as of December 31, 2018 and 2017.
Fair Value of Non-Financial Assets
The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregates properties and
other assets, at fair value on a nonrecurring basis. Refer to Note 10. Plant and Equipment, Net and Note 11. Mineral Rights, Net
for additional disclosures related to the fair value associated with the impaired assets.
105
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
15. Related Party Transactions
Cline Affiliates and Foresight Energy
Mr. Chris Cline, both individually and through another affiliate, Adena Minerals, LLC ("Adena"), owned a 31% interest in
NRP (GP) LP, NRP's general partner ("NRP GP"), through May 9, 2017. On May 9, 2017, Adena sold its 31% limited partner
interest in NRP GP to Great Northern Properties Limited Partnership (“GNPLP”) and Western Pocahontas Properties Limited
Partnership ("WPPLP") (the “Adena Sale”). GNPLP and WPPLP are companies controlled by Corbin J. Robertson, the Chairman
and Chief Executive Officer of GP Natural Resource Partners LLC (the general partner of NRP GP) (“GP LLC”). Upon closing
of this transaction, NRP no longer considers the various companies affiliated with Chris Cline, including Foresight Energy to be
affiliates of NRP. As a result, all transactions (including revenues, expenses and cash flows) after May 9, 2017 with the various
companies affiliated with Chris Cline, including Foresight Energy, are considered to be third party transactions.
Revenues and expenses related to transactions with Foresight Energy are included in the Partnership's Consolidated Statements
of Comprehensive Income as follows:
(In thousands)
Revenues:
Coal royalty and other
Coal royalty and other—affiliates
Transportation and processing services
Transportation and processing services—affiliate
Total
Expenses:
Operating and maintenance expense
Operating and maintenance expense—affiliates
Total
Coal Royalty and Other Revenues
For the Years Ended December 31,
2018
2017
2016
$
$
$
$
30,777
$
28,763
$
—
23,818
—
54,595
1,761
—
1,761
$
$
$
21,204
14,510
6,012
70,489
1,066
452
1,518
$
$
$
—
44,019
—
19,336
63,355
—
1,347
1,347
Various subsidiaries of Foresight Energy lease coal reserves from the Partnership. In addition, NRP owns a contractual
overriding royalty interest at Foresight Energy's Sugar Camp mine in the Illinois Basin which provides for payments based upon
production from specific tons at Foresight Energy's Sugar Camp operations on certain reserves owned by another affiliate of Chris
Cline. This overriding royalty is accounted for as a financing arrangement. Revenues related to these transactions are included in
Coal royalty and other revenues in the Partnership's Consolidated Statements of Comprehensive Income.
106
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Transportation and Processing Services Revenues and Expenses
The Partnership owns transportation and processing infrastructure related to certain of its coal properties, including loadout
and other transportation assets at Foresight Energy's Williamson and Macoupin mines in the Illinois Basin, for which it collects
throughput fees. These fees are included in Transportation and processing services revenues in the Partnership's Consolidated
Statements of Comprehensive Income.
NRP is responsible for operating and maintaining the rail loadout transportation assets at the Williamson mine and subcontracts
the operating responsibilities to a subsidiary of Foresight Energy. Expenses related to these operations are included in Operating
and maintenance expenses in the Partnership's Consolidated Statements of Comprehensive Income.
In addition, NRP owns rail loadout and associated infrastructure at the Sugar Camp mine, an Illinois Basin mine also operated
by a subsidiary of Foresight Energy LP. While the Partnership owns coal reserves at the Williamson and Macoupin mines, it does
not own coal reserves at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight
Energy and NRP collects throughput fees, which are included in Transportation and processing services revenues in the Partnership's
Consolidated Statements of Comprehensive Income.
NRP's Sugar Camp rail loadout lease with a subsidiary of Foresight Energy is accounted for as a financing lease. Minimum
lease payments are $5.0 million per year for the next five years and represent a $1.25 million per quarter deficiency payment. The
following table shows certain amounts related to NRP's Sugar Camp rail loadout facility financing lease:
(In thousands)
Projected remaining payments
Unearned income
Reimbursements to Affiliates of our General Partner
December 31,
2018
2017
$
66,495
$
25,058
71,452
28,366
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 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—affiliates and
General and administrative—affiliates on the Partnership's Consolidated Statements of Comprehensive Income. NRP also
reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain
rent, legal, accounting, treasury, information technology, insurance, 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—affiliates and General and administrative—affiliates on the Partnership's Consolidated Statements of Comprehensive
Income.
Direct general and administrative expenses charged to the Partnership by QMC and WPPLP are included in the Partnership's
Consolidated Statement of Comprehensive Income as follows:
(In thousands)
Operating and maintenance expenses—affiliates
General and administrative—affiliates
For the Years Ended December 31,
2018
2017
2016
$
6,170
$
6,184
$
3,658
4,989
8,119
3,591
During the years ended December 31, 2018, 2017 and 2016, the Partnership recognized $5.4 million, $1.5 million and $0.7
million in Operating and maintenance expenses—affiliates, respectively, on its Consolidated Statements of Comprehensive Income
related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007 in
which coal royalty revenues received from a third party by NRP are passed back to WPPLP.
107
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Included in Income from discontinued operations on the Partnership's Consolidated Statements of Income are $1.0 million,
$1.4 million and $3.1 million of Operating and maintenance expenses charged by QMC for the years ended December 31, 2018,
2017 and 2016, respectively.
At December 31, 2017, the Partnership had Other assets—affiliate from WPPLP on its Consolidated Balance Sheets related
to a non-production royalty receivable from WPPLP for overriding royalty interest of $0.2 million. The Partnership had Accounts
payable—affiliates on its Consolidated Balance Sheets to QMC of $0.5 million and WPPLP of $1.4 million as of December 31,
2018 and to QMC of $0.4 million and WPPLP of $0.1 million as of December 31, 2017.
Included in Liabilities from discontinued operations on the Partnerships Consolidated Balance Sheets is $0.1 million in
Accounts payable, affiliates, due to QMC as of December 31, 2018 and 2017, respectively.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), which controls several private
equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership
adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be
pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines
set forth in the Partnership's conflicts policy. At December 31, 2018, 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 is 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.
Coal related revenues from Corsa totaled $0.5 million, $1.3 million and $2.2 million for the years ended December 31, 2018,
2017 and 2016. At December 31, 2017, the Partnership had Accounts receivable—affiliates totaling $0.2 million from Corsa on
its Consolidated Balance Sheet.
Quinwood Coal Company Royalty
In May 2017, a subsidiary of Alpha Natural Resources assigned two coal leases with us to Quinwood Coal Company
("Quinwood"), an entity wholly owned by Corbin J. Robertson III. In connection with this lease assignment, Quinwood forfeited
the historical recoupable balance related to this property. As a result, NRP recognized $0.9 million of deferred minimum payments
received in prior periods from a subsidiary of Alpha as Coal royalty and other—affiliates revenue on its Consolidated Statements
of Comprehensive Income during the year ended December 31, 2017.
16. Major Customers
Revenues from customers that exceeded 10 percent of total revenues for any of the periods presented below are as follows:
(In thousands)
Foresight Energy
2018
2017
2016
Revenues
Percent
Revenues
Percent
Revenues
Percent
$
54,595
21.7% $
70,489
29.0% $
63,355
25.3%
For the Years Ended December 31,
Revenues from Foresight Energy are included within the Partnership's Coal Royalty and Other segment.
108
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
17. Commitments and Contingencies
Legal
NRP is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate
results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a
material effect on the Partnership’s financial position, liquidity or operations. During the year ended 2018, NRP was also involved
in the matters described below.
Anadarko Contingent Consideration Payment Dispute
In January 2013, NRP acquired a non-controlling 48.51% general partner interest in OCI Wyoming, L.P. ("OCI LP") and all
of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited
partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko").
The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical
Corporation.
The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by NRP if certain
performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015.
For those years, NRP paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment
obligations.
In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical
Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, NRP exchanged the stock
of OCI Co for a limited partner interest in OCI LP. Following the reorganization, NRP's interest in OCI LP increased to 49%,
consisting of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues,
management or control of OCI LP.
In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC in the District Court of Harris County, Texas, 157th
Judicial District. The complaint alleged that the transactions conducted in 2013 triggered an acceleration of NRP's obligation under
the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of
such amount, together with interest, court costs and attorneys’ fees. NRP does not believe the reorganization transactions triggered
an obligation to pay any additional contingent consideration and is vigorously defending this lawsuit. However, the ultimate
outcome cannot be predicted with certainty and the Partnership estimates a possible range of loss between $0, if it prevails, and
approximately $40 million, plus interest, court costs and attorneys’ fees if Anadarko prevails and is awarded the full damages it
seeks.
Foresight Energy Settlement
In October 2018, NRP's lawsuits against Foresight Energy and its subsidiaries Hillsboro Energy and Macoupin Energy were
settled. The Hillsboro suit was pending in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois, and the
Macoupin suit was pending in Macoupin County, Illinois. NRP received a payment of $25 million from Foresight Energy in full
settlement of the Hillsboro litigation, which was recognized immediately as Gain on litigation settlement in the Consolidated
Statement of Comprehensive Income. In addition, NRP and Hillsboro Energy amended the coal mining lease with respect to the
Deer Run mine to change the $30 million recoupable annual minimum royalty payments to $11 million non-recoupable annual
minimum payments effective January 1, 2019 and extended the current lease term through the end of 2033. Furthermore, Foresight
Energy forfeited its recoupable balances under the Macoupin and Hillsboro leases totaling approximately $37.4 million, the majority
of which NRP previously recognized in Cumulative effect of adoption of accounting standard in Partners' capital on its Consolidated
Balance Sheet on January 1, 2018. All claims were dismissed in both the Hillsboro and Macoupin lawsuits.
109
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Environmental Compliance
The operations the Partnership’s lessees conduct on its properties, as well as the aggregates/industrial minerals and oil and
gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. See
"Items 1. and 2. Business and Properties—Regulation and Environmental Matters." As an owner of surface interests in some
properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of
substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including
environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by
the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things,
environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership makes regular visits
to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. The Partnership
believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply
with environmental laws and regulations to 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, 2018. The Partnership is not associated with any material environmental
contamination that may require remediation costs. However, the Partnership’s lessees do 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.
18. 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 Board approval or, if earlier, the date the 2017 LTIP is terminated by the Board or
the committee appointed by the Board 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 of the Board, which determines the terms and conditions of awards granted
under the 2017 LTIP. The Partnership recognizes forfeitures for any awards issued under this plan as they occur.
Unit-Based Awards
Unit-based awards under the 2017 LTIP are generally issued to certain employees and non-employee directors of the
Partnership. Awards granted to employees vest at the end of a 3 year period and awards granted to non-employee directors are
immediately vested. Directors are given the option to take immediate issuance of the vested awards or defer such issuance until a
later date. Upon deferral of issuance, such units will continue to accumulate DERs until issuance.
In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem
DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between
the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if
the grantee ceases employment prior to vesting.
110
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
A summary of activity in the outstanding grants during 2018 is as follows:
(In thousands)
Outstanding grants at January 1, 2018
Granted
Fully vested and issued
Forfeitures
Outstanding at December 31, 2018
Common Units
Weighted
Average
Exercise Price
—
75
(17)
(2)
56
—
29.16
31.24
38.28
29.10
The awards granted in the first quarter of 2018 were valued using the closing price of NRP's units as of the grant date. The
grant date fair value of the 2017 LTIP awards granted during the period was $2.2 million, including awards granted to board
members with a grant date fair value of $0.6 million which immediately vested and of which $0.4 million were issued. Total unit-
based compensation expense recorded in the year ended December 31, 2018 associated with these awards was $1.0 million and
$0.1 million included in General and administrative expense and Operating and maintenance expense, respectively, in the
Partnership's Consolidated Statements of Comprehensive Income. The unamortized cost associated with unvested outstanding
awards as of December 31, 2018 is $1.2 million, which is to be recognized over a weighted average period of 2.1 years.
111
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following table summarizes quarterly financial data for 2018:
(In thousands, except per unit data)
Revenues (including affiliates)
Gain on litigation settlement
Gain on asset sales, net
Asset impairments
Income from operations
Net income from continuing operations
Income (loss) from discontinued operations
Net income
Net income attributable to NRP
Net income attributable to common
unitholders and general partner
Income from continuing operations per
common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
Weighted average number of common units
outstanding (basic)
Weighted average number of common units
outstanding (diluted)
First
Quarter (1) (2)
Second
Quarter (1) (2)
Third
Quarter (1)
Fourth
Quarter (3) (4) (5)
Total
2018
$
59,478
$
69,451
$
58,207
$
63,935
$
251,071
—
651
242
44,236
26,286
(1,948)
24,338
24,338
—
168
—
52,863
35,129
2,981
38,110
37,241
—
—
—
43,346
25,853
2,688
28,541
28,900
25,000
1,622
18,038
52,093
35,092
13,966
49,058
49,058
25,000
2,441
18,280
192,538
122,360
17,687
140,047
139,537
16,838
29,741
21,400
41,558
109,537
$
$
$
$
1.50
1.16
1.35
1.08
$
$
2.14
1.57
2.38
1.71
$
$
1.50
1.18
1.71
1.30
$
$
2.21
1.69
3.33
2.36
7.35
5.90
8.77
6.76
12,238
12,246
12,246
12,247
12,244
22,125
21,383
21,840
20,394
20,234
(1) As a result of the sale of its construction aggregates business, the Partnership classified the operating results related to this
business as discontinued operations in the Consolidated Statements of Comprehensive Income subsequent to the filing of
the Third Quarter 2018 Form 10-Q. See below for a reconciliation to the amounts reported in the Third Quarter 2018 Form
10-Q.
(2) During the third quarter of 2018 the Partnership identified an error related to its modified retrospective adoption of ASC 606
on January 1, 2018 for certain coal and aggregates royalty leases and revised its financial statements for the first and second
quarter of 2018 in its Third Quarter 2018 Form 10-Q.
(3) During the fourth quarter of 2018 the Partnership recorded $25 million in other income related to the Hillsboro litigation
settlement. See Note 17. Commitments and Contingencies for more information.
(4) During the fourth quarter of 2018 the Partnership sold its construction aggregates business for $205 million, before customary
purchase price adjustments and transaction expenses, and recorded a gain of $13.1 million included in Income from
discontinued operations on the Partnership's Consolidated Statement of Comprehensive Income. See Note 4. Discontinued
Operations for more information.
(5) During the fourth quarter of 2018 the Partnership recorded $18.0 million in aggregates and coal property impairment. See
Note 11. Mineral Rights, Net for more information.
112
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following tables reconcile the previously reported quarterly information to the quarterly financial data disclosed above:
(In thousands, except per unit data)
First Quarter 2018
Revenues (including affiliates)
Gain on asset sales, net
Asset impairments
Income from operations
Net income from continuing operations
Net loss from discontinued operations
Net income
Net income attributable to NRP
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
Second Quarter 2018
Revenues (including affiliates)
Gain on asset sales, net
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
Net income
Net income attributable to NRP
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
As Originally
Reported
Reclassified to
Discontinued
Operations
Revised
$
86,630
$
(27,152) $
59,478
660
242
42,322
24,352
(14)
24,338
24,338
16,838
$
$
1.35
1.08
1.35
1.08
12,238
22,125
$
$
$
109,860
$
210
55,878
38,144
(34)
38,110
37,241
29,741
$
$
2.38
1.71
2.38
1.71
12,246
21,383
$
$
(9)
—
1,914
1,934
(1,934)
—
—
—
$
0.15
0.09
— $
—
—
—
(40,409) $
(42)
(3,015)
(3,015)
3,015
—
—
—
(0.24) $
(0.14)
— $
—
—
—
651
242
44,236
26,286
(1,948)
24,338
24,338
16,838
1.50
1.16
1.35
1.08
12,238
22,125
69,451
168
52,863
35,129
2,981
38,110
37,241
29,741
2.14
1.57
2.38
1.71
12,246
21,383
113
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
As Originally
Reported
Reclassified to
Discontinued
Operations
Revised
(36,648) $
(163)
(2,720)
(2,712)
2,712
—
—
—
(0.22) $
(0.12)
— $
—
—
—
58,207
—
43,346
25,853
2,688
28,541
28,900
21,400
1.50
1.18
1.71
1.30
12,246
21,840
(In thousands, except per unit data)
Third Quarter 2018
Revenues (including affiliates)
Gain on asset sales, net
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
Net income
Net income attributable to NRP
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
$
94,855
$
163
46,066
28,565
(24)
28,541
28,900
21,400
$
$
1.71
1.30
1.71
1.30
$
$
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
12,246
21,840
114
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following table summarizes quarterly financial data for 2017:
(In thousands, except per unit data)
Revenues (including affiliates)
Gain on asset sales, net
Asset impairments
Income from operations
Debt modification expense
Loss on extinguishment of debt
Net income from continuing operations
Net income (loss) from discontinued
operations
Net income
Net income attributable to common
unitholders and general partner
Income from continuing operations per
common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
First
Quarter (1) (2)
Second
Quarter (1) (3)
Third
Quarter (1)
Fourth
Quarter (1)
Total
2017 (1)
$
61,432
$
58,015
$
58,406
$
64,927
$
242,780
29
1,778
38,124
7,807
—
7,588
(1,684)
5,904
3,184
—
47,522
132
4,107
23,153
2,837
25,990
154
—
43,052
—
—
178
1,189
47,861
—
—
23,079
28,665
2,987
26,066
2,042
30,707
3,545
2,967
176,559
7,939
4,107
82,485
6,182
88,667
3,404
18,452
18,416
22,942
63,214
$
$
$
$
0.41
0.50
0.28
0.28
$
$
1.25
1.01
1.47
1.13
$
$
1.24
0.94
1.48
1.07
$
$
1.67
1.18
1.84
1.26
4.57
3.68
5.06
3.96
Weighted average number of common units
outstanding (basic)
Weighted average number of common units
outstanding (diluted)
12,232
12,232
12,232
12,232
12,232
14,945
22,459
23,980
23,874
21,950
(1) As a result of the sale of its construction aggregates business, the Partnership classified the operating results related to this
business as discontinued operations in the Consolidated Statements of Comprehensive Income subsequent to the filing of
the 2017 Form 10-K. See below for a reconciliation to the amounts reported in the 2017 Form 10-K.
(2) During the first quarter of 2017 the Partnership incurred $7.8 million of debt modification costs as a result of the exchange
of $241 million of our 2018 Senior Notes for 2022 Senior Notes.
(3) During the second quarter of 2017 the Partnership incurred a $4.1 million loss on extinguishment of debt related to the
4.563% premium paid to redeem the 2018 Senior Notes in April 2017.
115
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
The following tables reconcile the previously reported quarterly information to the quarterly financial data disclosed above:
As Originally
Reported
Reclassified to
Discontinued
Operations
Revised
(In thousands, except per unit data)
First Quarter 2017
Revenues (including affiliates)
Gain on asset sales, net
Asset impairments
Income from operations
Debt modification expense
Net income from continuing operations
Net income (loss) from discontinued operations
Net income
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
$
88,653
$
44
1,778
37,042
7,807
6,111
(207)
5,904
3,404
$
$
0.30
0.30
0.28
0.28
$
$
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
12,232
14,945
Second Quarter 2017
Revenues (including affiliates)
Gain on asset sales, net
Income from operations
Debt modification expense
Loss on extinguishment of debt
Net income from continuing operations
Net income (loss) from discontinued operations
Net income
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
$
91,570
$
3,361
50,404
132
4,107
25,857
133
25,990
18,452
$
$
$
$
1.46
1.13
1.47
1.13
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
12,232
22,459
116
(27,221) $
(15)
—
1,082
—
1,477
(1,477)
—
—
$
0.12
0.10
— $
—
—
—
(33,555) $
(177)
(2,882)
—
—
(2,704)
2,704
—
—
(0.22) $
(0.12)
— $
—
—
—
61,432
29
1,778
38,124
7,807
7,588
(1,684)
5,904
3,404
0.41
0.50
0.28
0.28
12,232
14,945
58,015
3,184
47,522
132
4,107
23,153
2,837
25,990
18,452
1.25
1.01
1.47
1.13
12,232
22,459
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
As Originally
Reported
Reclassified to
Discontinued
Operations
Revised
(In thousands, except per unit data)
Third Quarter 2017
Revenues (including affiliates)
Gain on asset sales, net
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
Net income
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
$
93,116
$
171
46,531
26,499
(433)
26,066
18,416
$
$
1.51
1.08
1.48
1.07
$
$
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
12,232
23,980
Fourth Quarter 2017
Revenues (including affiliates)
Gain on asset sales, net
Asset impairments
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
Net income
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
$
100,822
$
280
1,253
49,998
30,741
(34)
30,707
22,942
$
$
1.84
1.26
1.84
1.26
$
$
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
12,232
23,874
117
(34,710) $
(17)
(3,479)
(3,420)
3,420
—
—
(0.27) $
(0.14)
— $
—
—
—
(35,895) $
(102)
(64)
(2,137)
(2,076)
2,076
—
—
(0.17) $
(0.09)
— $
—
—
—
58,406
154
43,052
23,079
2,987
26,066
18,416
1.24
0.94
1.48
1.07
12,232
23,980
64,927
178
1,189
47,861
28,665
2,042
30,707
22,942
1.67
1.18
1.84
1.26
12,232
23,874
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
As Originally
Reported
Reclassified to
Discontinued
Operations
Revised
(In thousands, except per unit data)
Total 2017
Revenues (including affiliates)
Gain on asset sales, net
Asset impairments
Income from operations
Debt modification expense
Loss on extinguishment of debt
Net income from continuing operations
Net income (loss) from discontinued operations
Net income
Net income attributable to common unitholders and general partner
Income from continuing operations per common unit
Basic
Diluted
Net income per common unit
Basic
Diluted
$
374,161
$
3,856
3,031
183,975
7,939
4,107
89,208
(541)
88,667
63,214
$
$
$
$
5.11
3.98
5.06
3.96
(131,381) $
(311)
(64)
(7,416)
—
—
(6,723)
6,723
—
—
—
(0.54) $
(0.30)
— $
—
—
—
242,780
3,545
2,967
176,559
7,939
4,107
82,485
6,182
88,667
63,214
4.57
3.68
5.06
3.96
12,232
21,950
Weighted average number of common units outstanding (basic)
Weighted average number of common units outstanding (diluted)
12,232
21,950
118
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, 2018. 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, 2018 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, 2018
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, 2018, 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.
119
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, 2018, 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, 2018, 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, 2018 and 2017, the related
consolidated statements of comprehensive income, partners’ capital and cash flows for each of the three years in the period ended
December 31, 2018, and the related notes and our report dated March 7, 2019 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 7, 2019
120
ITEM 9B. OTHER INFORMATION
None.
121
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
Jennifer L. Odinet
Kevin J. Craig
Kathryn S. Wilson
Gregory F. Wooten
Galdino J. Claro
Russell D. Gordy
Jasvinder S. Khaira
S. Reed Morian
Paul B. Murphy, Jr.
Richard A. Navarre
Corbin J. Robertson, III
Stephen P. Smith
Leo A. Vecellio, Jr.
Age
Position with the General
Partner
71 Chairman of the Board and Chief Executive Officer
57 President and Chief Operating Officer
44 Chief Financial Officer and Treasurer
40 Chief Accounting Officer
50 Executive Vice President, Coal
44 Vice President, General Counsel and Secretary
63 Vice President, Chief Engineer
59 Director
68 Director
37 Director
73 Director
59 Director
58 Director
48 Director
58 Director
72 Director
Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource
Partners LLC since 2002. Mr. Robertson has vast business experience having founded and served as a director and as an officer
of multiple companies, both private and public, and has served on the boards of numerous non-profit organizations. He has served
as the Chief Executive Officer and Chairman of the Board of the general partner of Great Northern Properties Limited Partnership
since 1992 and Quintana Minerals Corporation since 1978, as Chairman of the Board of Directors of New Gauley Coal Corporation
since 1986, and the general partner of Western Pocahontas Properties Limited Partnership since 1986. In addition, Mr. Robertson
served as Chief Executive Officer of the general partner of Western Pocahontas Properties Limited Partnership from 1986 until
2008 and currently serves on the Board of Managers of Premium Resources, LLC. He also serves as a Principal with Quintana
Capital Group, Chairman of the Board of the Cullen Trust for Higher Education and on the boards of the American Petroleum
Institute, the National Petroleum Council, the Baylor College of Medicine and the Spirit Golf Association. In 2006, Mr. Robertson
was inducted into the Texas Business Hall of Fame. Mr. Robertson is the father of Corbin J. Robertson, III.
122
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.
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.
Jennifer L. Odinet joined GP Natural Resource Partners LLC as Chief Accounting Officer in October 2017. Ms. Odinet most
recently served as Director, Financial Reporting for Cabot Oil & Gas Corporation, a publicly traded energy company, where she
was responsible for SEC and internal reporting, complex technical accounting matters and financial statement preparation and
analysis. Prior to joining Cabot, Ms. Odinet was a Senior Manager in the Assurance practice for PricewaterhouseCoopers LLC
from June 2000 to April 2010.
Kevin J. Craig has served as Executive Vice President, Coal of GP Natural Resource Partners since September 2014. Mr.
Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr. Craig also represents
NRP as one of its appointees to the Board of Managers of Ciner Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX
Transportation, where he served as Terminal Manager for the West Virginia Coalfields. He has extensive marketing, finance and
operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates having
been elected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate
Craig served as Chairman of the Committee on Energy. Mr. Craig did not seek re-election in 2014 and his term ended January
2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig has served as the Chairman of the
Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber
of Commerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He is involved in numerous
state coal associations and serves as a member of the Board of Directors of BrickStreet Mutual Insurance Company.
Kathryn S. Wilson has served as Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC since
December 2013. Ms. Wilson served as Associate General Counsel from March 2013 to December 2013. Since October 2013, Ms.
Wilson has also served as General Counsel and Secretary of each of New Gauley Coal Corporation, the general partner of Western
Pocahontas Properties Limited Partnership, and the general partner of Great Northern Properties Limited Partnership. She served
as General Counsel of Quintana Minerals Corporation from December 2013 to November 2018. Ms. Wilson practiced corporate
and securities law with Vinson & Elkins L.L.P. from September 2001 to February 2010 and from November 2011 to February
2013. Ms. Wilson served as General Counsel of Antero Resources Corporation from March 2010 to June 2011.
Gregory F. Wooten has served as Vice President, Chief Engineer of GP Natural Resource Partners LLC since December 2013.
Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP, Mr. Wooten served as Vice President, COO
and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties from 1982 until 2007.
Prior to 1982, Mr. Wooten worked as a planning and production engineer in the coal industry and is a member of the American
Institute of Mining, Metallurgical, and Petroleum Engineers. Mr. Wooten has served as Chairman of the National Council of Coal
Lessors since 2015.
123
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.
Russell D. Gordy joined the Board of Directors of GP Natural Resource Partners in October 2013. Mr. Gordy brings extensive
oil and gas industry, mineral interest and land ownership and financial experience to the Board. Mr. Gordy is currently managing
partner and majority owner in SG Interests, a producer of oil and coal bed methane gas, RGGS, which controls mineral acres
currently producing oil and gas, coal, iron ore, limestone, and copper, and Rock Creek Ranch. He is also President of Gordy Oil
Company, an oil and gas exploration company in the Gulf Coast of Texas and Louisiana, and Gordy Gas Corporation, an oil and
gas exploration company in the San Juan Basin of Colorado and New Mexico. Prior to forming SG Interests in 1989, Mr. Gordy
was a founding partner of Northwind Exploration Company an exploration company created in 1981 with former Houston Oil and
Minerals employees. Mr. Gordy served on the board of directors of Houston Exploration Company from 1987 until 2001.
Jasvinder S. Khaira joined the Board of Directors of GP Natural Resource Partners LLC in March 2017. Mr. Khaira brings
extensive financial and investing experience to the Board of Directors. Mr. Khaira currently is a Senior Managing Director in the
Tactical Opportunities group at The Blackstone Group L.P. Prior to joining Tactical Operations, Mr. Khaira was a member of
Blackstone's Private Equity Group and GSO Capital Partners. Mr. Khaira 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. Since joining Blackstone, Mr. Khaira has been involved in a variety of investments and
strategic business initiatives at Blackstone.
S. Reed Morian joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive
business experience having served as Chairman and Chief Executive Officer of several companies since the early 1980s and serving
on the board of other companies. Mr. Morian has served as a member of the Board of Directors of the general partner of Western
Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great
Northern Properties Limited Partnership since 1992. Mr. Morian also serves on the Board of Managers of Premium Resources,
LLC since 2006. Mr. Morian worked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief
Executive Officer from 1981 to 2006. He has also served as Chairman, Chief Executive Officer and President of DX Holding
Company since 1989. He formerly served on the Board of Directors for the Federal Reserve Bank of Dallas-Houston Branch from
April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March 2005 until April 2009.
Paul B. Murphy, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Murphy is the
Chairman and Chief Executive Officer and a Director of Cadence Bancorporation and Chairman of Cadence Bank, N.A. He has
served at Cadence and its predecessors since December 2009. Cadence is a $17 billion bank holding company headquartered in
Houston and it is traded on the NYSE (CADE). Previously, Mr. Murphy spent 20 years at Amegy Bank of Texas, helping to steer
that institution from $75 million in assets and a single location to assets of $11 billion and 85 banking centers at the time of his
departure as the Chief Executive Officer and a Director in 2009. Mr. Murphy is an advocate of the community and is a board
member of Oceaneering International, Inc. and the Houston Hispanic Chamber of Commerce. He is active in the World Presidents
Organization.
124
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. From 1993 until
2012, Mr. Navarre held several executive positions with Peabody Energy Corporation, including President-Americas from March
2012 to June 2012, President and Chief Commercial Officer from January 2008 to March 2012, Executive Vice President of
Corporate Development and Chief Financial Officer from July 2006 to January 2008 and Chief Financial Officer from October
1999 to June 2008. Since his retirement from Peabody Energy in 2012, Mr. Navarre has provided advisory services to the coal
industry and private equity firms. Mr. Navarre serves on the Board of Directors of Civeo Corporation, where he serves as Chairman,
Covia Corporation, where he serves as Chairman, and Arch Coal, where he serves on the Audit committee. He is a member of the
Hall of Fame of the College of Business and a member of the Board of Advisors of the College of Business and Administration
of Southern Illinois University Carbondale. He is the former Chairman of the Bituminous Coal Operators’ Association and former
advisor to the New York Mercantile Exchange. Mr. Navarre is a Certified Public Accountant. Mr. Navarre also has been involved
in numerous civic and charitable organizations throughout his career.
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.
125
Corporate Governance
Board Meetings and Executive Sessions
The Board met 10 times in 2018. During 2018, our non-management directors met in executive session several times. The
presiding director was Mr. Vecellio, the Chairman of our Compensation, Nominating and Governance Committee, or CNG
Committee. In addition, our independent directors met one time in executive session in December 2018. Mr. Vecellio was the
presiding director at that meeting. Interested parties may communicate with our non-management directors by writing a letter to
the Chairman of the CNG Committee, NRP Board of Directors, 1201 Louisiana Street, Suite 3400, Houston, Texas 77002.
Independence of Directors
The Board of Directors has affirmatively determined that Messrs. Claro, Gordy, Navarre, Smith and Vecellio are independent
based on all facts and circumstances considered by the Board, including the standards set forth in Section 303A.02(a) of the NYSE’s
listing standards. Because we are a limited partnership as defined in Section 303A of the NYSE’s listing standards, we are not
required to have a majority of independent directors on the Board. The Board has an Audit Committee, a Compensation, Nominating
and Governance Committee, and a Conflicts Committee, each of which is staffed solely by independent directors.
Audit Committee
Our Audit Committee is currently comprised of Mr. Smith, who serves as chairman, Mr. Claro and Mr. Navarre. Mr. Smith,
Mr. Claro, and Mr. Navarre are "Audit Committee Financial Experts" as determined pursuant to Item 407 of Regulation S-K.
During 2018, the Audit Committee met seven times. Mr. Claro joined the Audit Committee effective March 2, 2018. Mr. Gordy
served as a member of the Audit Committee from January 1, 2018 through March 1, 2018.
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 2018, 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, 2018 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 Committee also discussed with the independent auditors other matters required to be discussed by the auditors with the
Committee by PCAOB Auditing Standard No. 16, Communications With Audit Committees. The Committee received and discussed
with the auditors their annual written report on their independence from the partnership and its management, which is made under
Rule 3526, Communication With Audit Committees Concerning Independence, and considered with the auditors whether the
provision of non-audit services provided by them to the partnership during 2018 was compatible with the auditors’ independence.
126
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 2018, 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, 2018, for filing with the Securities and Exchange Commission.
Stephen P. Smith, Chairman
Galdino J. Claro
Richard A. Navarre
Compensation, Nominating and Governance Committee
Executive officer compensation is administered by the CNG Committee, which is currently comprised of three members:
Mr. Vecellio, as Chairman, Mr. Gordy and Mr. Smith. The CNG Committee has reviewed and approved the compensation
arrangements described in the Compensation Discussion and Analysis section of this Annual Report on Form 10-K. During 2018,
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.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires directors, officers and persons who beneficially own more than ten percent of a
registered class of our equity securities to file with the SEC and the NYSE initial reports of ownership and reports of changes in
ownership of their equity securities. These people are also required to furnish us with copies of all Section 16(a) forms that they
file. Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting
persons that no Forms 5 were required for transactions occurring in 2017, and we believe that, except as provided below, our
officers and directors and persons who beneficially own more than ten percent of a registered class of our equity securities complied
with all filing requirements with respect to transactions in our equity securities during 2018. On June 11, 2018, Mr. Murphy filed
a Form 4 reporting purchase of 3,159 common units on June 5, 2018 and 3,659 common units on June 6, 2018 that had not been
previously reported on a timely basis.
127
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 2018, 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.
128
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Overview
As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a
typical public corporation. Our executive officers based in Houston, Texas are employed by Quintana Minerals Corporation
(“Quintana”), and our executive officers based in Huntington, West Virginia are employed by Western Pocahontas Properties
Limited Partnership (“Western Pocahontas”). Quintana and Western Pocahontas are controlled by our Chairman and Chief
Executive Officer and are affiliates of NRP. While our executive officers are employed by affiliates of NRP, each of them has been
appointed to serve as an executive officer of GP Natural Resource Partners LLC (“GP LLC”), the general partner of NRP (GP)
LLC (“NRP GP”), the general partner of NRP. For a more detailed description of our structure, see "Items 1. and 2. Business and
Properties—Partnership Structure and Management" in this Annual Report on Form 10-K.
Although our executives’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse
those companies based on the time allocated to NRP by each executive officer. Our reimbursement for the compensation of executive
officers is governed by our partnership agreement. For purposes of this Compensation Discussion and Analysis, our “named
executive officers” are:
• Corbin J. Robertson, Jr.—Chairman and Chief Executive Officer
• Craig W. Nunez—President and Chief Operating Officer
• Christopher J. Zolas—Chief Financial Officer and Treasurer
• Kathryn S. Wilson—Vice President, General Counsel and Secretary
•
•
Jennifer L. Odinet—Chief Accounting Officer
Perry W. Donahoo—Former Chief Executive Officer—VantaCore
Executive Officer Compensation Strategy and Philosophy
Under our partnership agreement, we are required to distribute all of our available cash each quarter. Historically, our primary
business objective was to generate cash flows at levels that could sustain long-term quarterly cash distributions to our investors.
However, given the difficult coal markets over the past few years, coupled with the limitations on our ability to access capital from
additional sources, our current objective is to preserve long-term equity value for our unitholders by using our excess free cash
flow to reduce our leverage. Our objective in determining the compensation of our executive officers is to retain qualified people
to manage the business under current market conditions. Incentive compensation for the year ended December 31, 2018 was
discretionary but certain performance criteria were considered as factors, as further described under “—Components of
Compensation.”
The 2018 compensation for executive officers consisted of four primary components:
•
•
•
•
base salaries;
short-term cash incentive compensation;
long-term cash incentive compensation; and
perquisites and other benefits.
All our named executive officers, other than Corbin J. Robertson, Jr., our Chairman and Chief Executive Officer, spent 100%
of their time on NRP matters during 2018, and NRP bears the proportionate cost of their time. Mr. Robertson does not receive a
salary in his capacity as Chief Executive Officer. Mr. Robertson is compensated through short-term cash and long-term equity
incentive awards.
129
Historically, in February of each year, the CNG Committee has approved the short-term cash incentive award for the year
just ended and long-term incentive awards for the executive officers. The CNG Committee considers the performance of the
partnership, the performance of the individuals and the outlook for the future in determining the amounts of the awards. Prior to
2016, we issued phantom units, coupled with tandem distribution equivalent rights (“DERs”), to our executive officers that were
paid in cash based on the average closing price of our common units for the 20-day trading period prior to vesting. The phantom
units and DERs typically vested four years from the date of grant, with the last grants of these awards vested in February 2019.
We refer to these phantom units as “Cash Settled Phantom Units.”
In December 2017, the CNG Committee approved and the Board adopted the Natural Resource Partners 2017 Long-Term
Incentive Plan (the “2017 Plan”), subject to unitholder approval. On December 20, 2017, unitholders holding the requisite percentage
of votes necessary to approve the 2017 Plan approved the 2017 Plan by written consent in lieu of a special meeting of unitholders.
The 2017 Plan became effective on January 16, 2018. Beginning in February 2018, the CNG Committee has made awards of
phantom units to be settled in common units under the 2017 Plan to NRP’s officers in order to incentivize management while also
aligning the long-term interests of management with the interests of NRP’s unitholders.
Role of Compensation Experts
Neither the Board nor the CNG Committee retained any consultants to evaluate compensation of officers or directors in 2018.
Role of Our Executive Officers in the Compensation Process
With respect to 2018 salaries and short-term cash incentive awards and long-term equity incentive awards, Mr. Nunez, our
President and Chief Operating Officer, provided Mr. Robertson with recommendations relating to the executive officers other than
himself. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of
the executive officers other than himself. Messrs. Robertson and Nunez considered the factors described elsewhere in this
compensation discussion and analysis in recommending, in their discretion, the appropriate amounts for each named executive
officer. Messrs. Robertson and Nunez attended the CNG Committee meetings at which the Committee deliberated and approved
2018 salaries, short-term cash incentive awards and long-term equity incentive awards but were excused from the meetings when
the CNG Committee discussed their compensation.
Components of Compensation
Base Salaries
With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our executive
officers are paid an annual base salary by Quintana or Western Pocahontas for services rendered to us by the executive officers
during the fiscal year. We then reimburse Quintana and Western Pocahontas based on the time allocated by each executive officer
to our business. The base salaries of our named executive officers are reviewed on an annual basis as well as at the time of a
promotion or other material change in responsibilities. The CNG Committee reviews and approves the full salaries paid to each
executive officer by Quintana and Western Pocahontas, based on both the actual time allocations to NRP in the prior year and the
anticipated time allocations in the coming year. Adjustments in base salary are based on an evaluation of individual performance,
our partnership’s overall performance during the fiscal year and the individual’s contribution to our overall performance.
In determining salaries for NRP’s executive officers for 2018, at the December 2017 meeting, the CNG Committee considered
the financial performance of NRP for the nine months ended September 30, 2017 as well as the projected financial performance
of NRP for the fourth quarter of 2017 and for the year ending December 31, 2018. The CNG Committee also considered the
individual performance of each member of the executive management team during 2017. Salaries for 2018 are shown in the
Summary Compensation Table below.
130
Short-Term Cash Incentive Compensation
Each named executive officer received a discretionary short-term cash incentive award approved in February 2019 by the
CNG Committee. The amounts awarded with respect to 2018 under this program are disclosed in the Summary Compensation
Table under the Bonus column. With respect to 2018, the CNG Committee provided general guidelines that cash bonuses would
be paid based on a range of 60% to 140% of base salary, with Mr. Robertson receiving two times the amount awarded to the
President and Chief Operating Officer. In addition, the CNG Committee determined that it would consider certain criteria to
determine bonus amounts within this range, but that the criteria utilized at the time of determination, as well as the relative weight
of those criteria, would be generally discretionary and subject to change based on developments at the company.
Long-Term Equity Incentive Compensation
Each named executive officer received a discretionary long-term equity incentive award in 2018 under the 2017 Plan. The
2018 awards were made in the form of phantom units that will settle in NRP common units on a one-for-one basis following vesting
in February 2021 and will accrue DERs to be paid in cash upon settlement. We refer to these phantom units issued in 2018 as
“2017 Plan Phantom Units.” The 2017 Plan Phantom Units are subject to forfeiture and will vest on an accelerated basis following
death or disability of the award recipient or following a change in control of NRP. The grant date fair value of the 2017 Plan
Phantom Units awarded in 2018 are disclosed in the Summary Compensation Table under the Stock Awards column. For the 2017
Plan Phantom Units awarded in 2018, the CNG Committee generally awarded an amount equal to 60% of base salary, with Mr.
Robertson receiving two times the amount awarded to the President and Chief Operating Officer. The CNG Committee considered
performance of the company and individual performance in making these awards, as well as the cash incentive awards received
by certain of the named executive officers in March 2017.
Perquisites and Other Personal Benefits
Both Quintana and Western Pocahontas maintain employee benefit plans that provide our executive officers and other
employees with the opportunity to enroll in health, dental and life insurance plans. Each of these benefit plans require the employee
to pay a portion of the health and dental premiums, with the company paying the remainder. These benefits are offered on the same
basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee
allocates time to our business.
In 2018, Quintana and Western Pocahontas maintained tax-qualified 401(k) and defined contribution retirement plans. During
2018, Quintana and Western Pocahontas matched 100% of the first 6.0% of the employee contributions under their respective
401(k) plans. As with the other contributions, any amounts contributed by Quintana and Western Pocahontas are reimbursed by
us based on the time allocated by the employee to our business. None of NRP, Quintana or Western Pocahontas maintains a pension
plan or a defined benefit retirement plan.
Unit Ownership Requirements
NRP maintains Unit Ownership and Retention Guidelines (the “ownership guidelines”) that are administered by the CNG
Committee and require NRP’s officers who are required to file ownership reports under Section 16 of the Securities Exchange Act
of 1934 (the “Exchange Act”) and certain other officers as designated from time-to-time by the Board or the CNG Committee to
retain all common units awarded under any NRP incentive plan (net of any units withheld or sold to cover tax liabilities) until
certain ownership guidelines are met. The guideline for NRP’s President and Chief Operating Officer is for such individual to hold
common units having a value of four times his or her base salary at the date of measurement. The guideline for NRP’s Chief
Financial Officer is for such individual to hold common units having a value of two times his or her base salary at the date of
measurement. The guideline for NRP’s Vice President & General Counsel and Chief Accounting Officer is for such individuals
to hold common units having a value of one and one-half times his or her base salary at the date of measurement. There is no
minimum time period required to achieve the unit ownership guidelines. Due to his substantial ownership in us, the ownership
guidelines do not currently apply to our Chief Executive Officer.
The ownership guidelines also require directors who are not officers to retain common units with a value equal to three times
the amount of the annual cash retainer paid to directors. Directors are required to achieve the unit ownership guideline within five
years. Until the unit ownership guideline is achieved, each director is encouraged to retain all common units awarded under any
NRP incentive plan (net of any units sold to cover tax liabilities).
131
Units that count towards the satisfaction of the officer and director guidelines include common units held directly by the
executive officer or director, common units owned indirectly by the executive officer or director (e.g., by a spouse or other immediate
family member residing in the same household or a trust for the benefit of the executive officer or director or his or her family),
units granted under NRP’s long-term incentive plans (including phantom units representing the right to receive units), and units
purchased in the open market (whether purchased before or after the effective date of the ownership guidelines).
Incentive Compensation Recoupment Policy
NRP maintains the Natural Resource Partners L.P. Incentive Compensation Recoupment Policy, which is administered by
the CNG Committee. The policy authorizes the Board or committee thereof to recoup incentive compensation in the event of a
restatement of financial statements due to material non-compliance with securities laws, fraud or misconduct.
Securities Trading Policy
Our insider trading policy states that executive officers and directors may not purchase or sell puts or calls to sell or buy our
common units, engage in short sales with respect to our common units, or buy our securities on margin.
Report of the Compensation, Nominating and Governance Committee
The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of
Regulation S-K with management. Based on the reviews and discussions referred to in the foregoing sentence, the CNG Committee
recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for
the year ended December 31, 2018.
Leo A. Vecellio, Jr., Chairman
Russell D. Gordy
Stephen P. Smith
132
Summary Compensation Table
The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation for 2016, 2017
and 2018:
Name and Principal Position
Year
Salary ($)
Bonus ($)
Corbin J. Robertson, Jr.—Chief Executive Officer
Non-Equity
Incentive Plan
Compensation
($)
Stock Awards
($) (1)
All Other
Compensation
($) (2)
Total ($)
2018
2017
2016
— 1,208,247
—
—
—
—
—
3,250,000
—
418,836
—
—
—
—
—
1,627,083
3,250,000
—
Craig W. Nunez—President and Chief Operating Officer
2018
2017
2016
447,499
375,000
375,000
604,124
250,000
425,000
—
1,218,750
—
209,433
—
—
16,800
34,650
34,383
1,277,856
1,878,400
834,383
Christopher J. Zolas—Chief Financial Officer
2018
2017
2016
337,499
300,000
300,000
455,624
180,000
200,000
—
375,000
—
167,529
—
—
16,800
34,650
34,383
977,452
889,650
534,383
Kathryn S. Wilson—Vice President, General Counsel and Secretary(3)
2018
2017
2016
469,124
150,000
225,000
347,499
321,750
305,500
—
975,000
—
139,622
—
—
16,800
34,304
31,631
973,045
1,481,054
562,131
Jennifer L. Odinet—Chief Accounting Officer(4)
2018
287,082
387,561
—
148,003
16,800
839,446
Perry W. Donahoo—Former Chief Executive Officer—VantaCore(5)
2018
314,767
314,767
—
170,322
2,367,756
3,167,612
(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 18. Unit-Based
Compensation" elsewhere in this Annual Report on Form 10-K for more information.
(2) Includes portions of 401(k) matching allocated to Natural Resource Partners by Quintana and Western Pocahontas.
(3) Ms. Wilson allocated approximately 94%, 99% and 100% of her time to NRP during the years ended December 31, 2016,
2017 and 2018, respectively, and amounts included in the table reflect this allocation.
(4) Ms. Odinet was not a named executive officer for purposes of this table during the years ended December 31, 2016 or
2017.
(5) Mr. Donahoo was not a named executive officer for purposes of this table during the years ended December 31, 2016 or
2017 and resigned as Chief Executive Officer—VantaCore effective December 11, 2018 in connection with our sale of
that business. Upon his resignation, and in accordance with his employment agreement with Quintana, Mr. Donahoo
received a severance payment of $500,399, which will be paid out in equal monthly installments during 2019. This severance,
as well as a transaction bonus paid to Mr. Donahoo in connection with the VantaCore sale, are disclosed under the All
Other Compensation column. See “—Employment Agreements.”
133
Grants of Plan-Based Awards in 2018
The following table shows the 2017 Plan Phantom Units granted to named executive officers during 2018. The awards in
the table below will vest in February 2021, and upon settlement, an equivalent number of common units will be issued to each
named executive officer, subject to withholding. The 2017 Plan Phantom Units also accrue DERs from the grant date, which will
be paid out in cash upon settlement following and subject to vesting.
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Jennifer L. Odinet
Perry W. Donahoo(1)
2017 Plan Phantom Units
Grant Date
Number of Units
Grant Date Fair Value
2/14/2018
2/14/2018
2/14/2018
2/14/2018
2/14/2018
2/14/2018
$
14,393
7,197
5,757
4,798
5,086
5,853
418,836
209,433
167,529
139,622
148,003
170,322
(1) Mr. Donahoo’s phantom units vested in full on December 11, 2018, the date of the sale of VantaCore. His phantom units
were net settled for tax purposes, resulting in the issuance by us of 3,549 common units and a cash payment of the associated
accrued DERs.
Employment Agreements
We sold our construction aggregates business, VantaCore, on December 11, 2018. Mr. Donahoo served as Chief Executive
Officer of VantaCore and was employed by Quintana. Pursuant to his employment agreement with Quintana, Mr. Donahoo was
entitled to certain benefits upon NRP’s sale of the VantaCore business. Accordingly, in December 2018, Mr. Donahoo received a
bonus amount equal to 100% of his 2018 base salary prorated through the sale date. In addition, the vesting of all of Mr. Donahoo’s
Cash Settled Phantom Units and 2017 Plan Phantom Units was accelerated to the closing date, and Mr. Donahoo received cash
and common units accordingly. Finally, pursuant to his employment agreement, Mr. Donahoo is entitled to receive an amount
equal to 18 months of his 2018 base salary, or $500,399, to be paid in equal installments each month during 2019.
None of our other named executive officers has an employment agreement.
Phantom Units Vested in 2018
The table below shows the Cash Settled Phantom Units and 2017 Plan Phantom Units that vested in 2018 with respect to
each named executive officer, along with value realized by each individual:
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Jennifer L. Odinet
Perry W. Donahoo
Equity Awards During 2018
Cash Settled
Phantom Units
2017 Plan Phantom
Units
Value Realized on
Vesting(1)
3,360
1,300
800
683
—
1,743(2)
— $
—
—
—
—
5,853(3)
174,678
53,934
30,390
35,507
—
314,369
(1) Includes DERs accrued from the issue date to the settlement date.
(2) Includes 850 phantom units that vested February 2018 and 893 phantom units vested in December 2018 in connection with
the VantaCore sale, each of which settled in cash based on the average closing price of NRP’s common units for the 20
trading days prior to the vesting date.
134
(3) 2017 Plan Phantom Units vested in full in December 2018 in connection with the VantaCore sale at a price of $38.28, the
closing price of NRP’s common units on the closing date of the sale.
Outstanding Equity Awards at December 31, 2018
The table below shows the total number of outstanding Cash Settled Phantom Units and 2017 Plan Phantom Units held by
each named executive officer at December 31, 2018.
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Jennifer L. Odinet
Perry W. Donahoo
Unvested
Cash Settled
Phantom Units(1)
Market Value
of Unvested Cash
Settled
Phantom Units (2)
Unvested 2017 Plan
Phantom Units(3)
Market Value of
Unvested 2017 Plan
Phantom Units(2)
$
3,600
1,400
950
950
—
—
137,664
53,536
36,328
36,328
—
—
$
14,393
7,197
5,757
4,798
5,086
—
550,388
275,213
220,148
183,476
194,489
—
(1) Cash Settled Phantom Units were awarded in February 2015 and vested in February 2019.
(2) Based on a unit price of $38.24, the closing price for the common units on December 31, 2018.
(3) 2017 Plan Phantom Units were awarded in February 2018 and vest in February 2021.
Potential Payments upon Termination or Change in Control
Upon the occurrence of a change in control of NRP, our general partner, or GP Natural Resource Partners LLC, any outstanding
Cash Settled Phantom Units and 2017 Plan Phantom Units held by each of our named executive officers would immediately vest
and become payable. The table below indicates the estimated payments to each named executive officer following a change in
control at December 31, 2018.
Named Executive Officer
Corbin J. Robertson, Jr.
Craig W. Nunez
Christopher J. Zolas
Kathryn S. Wilson
Jennifer L. Odinet
Perry W. Donahoo(3)
Cash Settled Phantom Units
2017 Plan Equity Awards
Unvested
Phantom
Units
3,600
1,400
950
950
—
893
Market
Value(1)
$ 135,580
52,725
35,778
35,778
—
33,631
Accumulated
DERs
27,540
10,710
7,268
7,268
—
6,831
Unvested
Phantom
Units
14,393
7,197
5,757
4,798
5,086
5,853
Market
Value(2)
$ 550,388
275,213
220,148
183,476
194,489
223,819
Accumulated
DERs
19,431
9,716
7,772
6,477
6,866
7,902
Total
Potential
Payments
$ 732,938
348,365
270,965
232,998
201,355
272,183
(1) Calculated based on a per unit price of $37.661, the average closing price for our common units for the 20 trading days
ended December 31, 2018, as required by the terms of the phantom unit agreements.
(2) Calculated based on a unit price of $38.24, the closing price for the common units on December 31, 2018.
(3) Amounts represent what Mr. Donahoo would have received if he had been an officer at December 31, 2018. Amounts
actually received by Mr. Donahoo are shown in the table under “—Phantom Units Vested in 2018.” In accordance with
his employment agreement with Quintana, if a change in control of NRP had occurred on December 31, 2018, Mr. Donahoo
was also entitled to receive cash payment of $500,399 payable over the following 12 months, a cash bonus of $314,767,
and reimbursement of COBRA premiums up to $40,616.
135
Directors’ Compensation for the Year Ended December 31, 2018
During the year ended December 31, 2018, there were a number of changes to the Board and the committees thereof:
• Effective January 1, 2018 through March 1, 2018, Mr. Russell D. Gordy served on the Audit Committee.
• Effective March 2, 2018, Mr. Paul B. Murphy, Jr. joined the Board; and
• Effective March 2, 2018, Mr. Galdino J. Claro joined the Board and the Audit Committee and the Conflicts Committee;
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 2018 consisted of a $75,000 cash retainer and an award of common units under the 2017 Plan. The units awarded to Board
members are fully vested and not subject to forfeiture; however, the Board members had the option in advance of receipt of the
award to elect to defer settlement of the award until after 90 days following such director’s retirement or earlier departure from
the Board. In addition, members of Board committees received $5,000 for each committee served on, and each committee chairman
received an additional $10,000 for acting as chairman.
The table below shows the directors’ compensation for the year ended December 31, 2018:
Name of Director
Russell D. Gordy
Jasvinder S. Khaira(2)
S. Reed Morian
Richard A. Navarre(3)
Corbin J. Robertson, III
Stephen P. Smith(3)
Leo A. Vecellio, Jr.
Paul B. Murphy, Jr.(4)
Galdino J. Claro(4)
Fees Earned or Paid in
Cash
2017 Plan Common
Unit Awards(1)
Total Compensation
$
81,250
$
69,811
$
—
75,000
95,000
75,000
95,000
95,000
62,500
70,833
—
69,811
69,811
69,811
69,811
69,811
65,202
65,202
151,061
—
144,811
164,811
144,811
164,811
164,811
127,702
136,035
(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 19 to the audited consolidated financial statements included elsewhere in this Annual
Report on Form 10-K.
(2) Mr. Khaira does not receive Board compensation as the Blackstone designee.
(3) Messrs. Navarre and Smith elected to defer settlement of their common units awarded under the 2017 Plan until 90 days
following their respective retirements or earlier departures from the Board.
(4) Amounts prorated from March 2, 2018, the date Messrs. Murphy and Claro joined the Board.
136
The table below shows the Cash Settled Phantom Units that vested in 2018 with respect to each Director, along with the
value realized by each individual, including the DERs accruing from the February 2014 grant date. Each director, other than Messrs.
Khaira, Murphy, and Claro also held 410 Cash Settled Phantom Units as of December 31, 2018.
Name of Director
Russell D. Gordy
Jasvinder S. Khaira
S. Reed Morian
Richard A. Navarre
Corbin J. Robertson, III
Stephen P. Smith
Leo A. Vecellio, Jr.
Paul B. Murphy, Jr.
Galdino J. Claro
Cash Settled
Phantom Units
Value Realized
on Vesting
$
389
—
389
389
389
389
389
—
—
20,223
—
20,223
20,223
20,223
20,223
20,223
—
—
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2018, Messrs. Vecellio, Gordy, and Smith served on the CNG Committee. None of
Messrs. Vecellio, Gordy, and Smith has ever been an officer or employee of NRP or GP Natural Resource Partners LLC. None of
our executive officers serve as a member of the board of directors or compensation committee of any entity that has any executive
officer serving as a member of our Board or CNG Committee.
Pay Ratio Disclosure
The Securities and Exchange Commission has adopted a rule requiring annual disclosure of the ratio of the median employee’s
total annual compensation to the total annual compensation of the CEO.
The personnel providing services to us, including our executive officers, are employed by Quintana or Western Pocahontas.
As of December 31, 2018, 57 such persons were providing services to us. We identified a new median service provider in 2018
by examining the 2018 total taxable compensation, as reflected in our payroll records as reported to the Internal Revenue Service
on Form W-2, for all individuals who provided services to us as of December 31, 2018. The calculation does not include
compensation paid to employees of the VantaCore construction aggregates business sold in December 2018. We did not make any
assumptions, adjustments, or estimates with respect to total cash compensation or equity compensation and we did not annualize
the compensation for any service providers that were not employed for all of 2018.
After identifying the median service provider based on total compensation, we calculated annual 2018 compensation for the
median service provider using the same methodology used to calculate the Chief Executive Officer’s total compensation as reflected
in the Summary Compensation Table above. The median service provider’s annual 2018 compensation was as follows:
Name
Year
Salary
Bonus
Non-Equity
Incentive Plan
Compensation
Phantom
Unit Awards
All Other
Compensation
Total
Median Service
Provider
2018
$
88,400
$
20,000
$
— $
— $
5,304
$ 113,704
Our 2018 ratio of Chief Executive Officer total compensation to our median service provider's total compensation is
reasonably estimated to be 14:1.
137
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following tables set forth, as of March 1, 2019, 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)
Premium Resources LLC (3)
JPMorgan Chase & Co. (4)
The Goldman Sachs Group, Inc. (5)
Craig W. Nunez
Kathryn S. Wilson
Christopher J. Zolas
Perry W. Donahoo (6)
Jennifer L. Odinet
Galdino J. Claro
Russell D. Gordy (7)
Jasvinder S. Khaira
S. Reed Morian
Paul B. Murphy, Jr.
Richard A. Navarre
Corbin J. Robertson III (8)
Stephen P. Smith
Leo A. Vecellio, Jr.
Directors and Officers as a Group
*
Less than one percent.
Common
Units
Percentage of
Common
Units (1)
4,128,605
4,128,599
1,154,442
785,207
—
—
—
7,504
—
4,114
11,354
—
4,354
7,614
1,000
177,144
355
6,354
4,341,844
33.7%
33.7%
9.4%
6.4%
—
—
—
—
—
*
*
*
*
*
*
1.4%
*
*
35.4%
(1) Percentages based upon 12,261,199 common units issued and outstanding as of March 1, 2019. Unless otherwise noted,
beneficial ownership is less than 1%.
(2) Mr. Robertson may be deemed to beneficially own the 4,128,599 common units owned by Premium Resources LLC.
Mr. Robertson’s address is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.
(3) These common units may be deemed to be beneficially owned by Mr. Robertson. The address of Premium Resources LLC
is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.
(4) According to a Schedule 13G filing with the SEC on January 29, 2019, JPMorgan Chase & Co. holds sole voting power
and sole dispositive power with respect to 1,154,442 common units in the Partnership. The business address of JPMorgan
Chase & Co. is 270 Park Ave., New York, NY 10017.
(5) According to a Schedule13G filing with the SEC on February 7, 2019, The Goldman Sachs Group holds shared voting
power and shared dispositive power with respect to 785,207 common units in the Partnership. The business address of The
Goldman Sachs Group is 200 West Street, New York, NY 10282.
(6) Mr. Donahoo resigned as Chief Executive Officer—Construction Aggregates in December 2018 in connection with our
sale of that business and is one of our Named Executive Officers for purposes of this Annual Report on Form 10-K.
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(7) Mr. Gordy may be deemed to beneficially own 5,000 common units owned by Minion Trail, Ltd. and 2,000 common units
owned by Rock Creek Ranch 1, Ltd.
(8) Mr. 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, 5,046 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: 41,743 common units
owned directly by Mr. Robertson III.
Name of Beneficial Owner
The Blackstone Group L.P. (1)
GoldenTree Asset Management, LP (2)
Preferred Units
Percentage of
Preferred Units
142,500
107,500
57%
43%
(1) The Preferred Units are owned by funds managed by The Blackstone Group L.P., whose address is 345 Park Ave, New
York, NY 10154. Blackstone Group Management L.L.C. is the general partner of The Blackstone Group L.P., and is wholly
owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman.
(2) The Preferred Units are owned by funds managed by GoldenTree Asset Management, LP, whose address is 300 Park Ave,
New York, NY 10022. Steven A. Tananbaum serves as senior managing member of GoldenTree Asset Management LLC,
the general partner of GoldenTree Asset Management, LP.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, and Great Northern Properties Limited
Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer
to these companies collectively as the WPP Group. Corbin J. Robertson, Jr. owns the general partner of Western Pocahontas
Properties, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman and Chief Executive
Officer of New Gauley Coal Corporation.
Omnibus Agreement
As part of the omnibus agreement entered into concurrently with the closing of our initial public offering, the WPP Group
and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the “GP affiliates,” each agreed that
neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each,
a "restricted business") in the specific circumstances described below:
•
•
the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned
fee coal reserves within the United States; and
the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within
the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.
"Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more
intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described
below, the WPP Group and their respective controlled affiliates will not be prohibited from engaging in activities in which they
compete directly with us.
A GP affiliate may, directly or indirectly, engage in a restricted business if:
•
•
•
the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value
of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must
offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided
that if the fair market value of the assets of the restricted business subsequently exceeds $10 million, the GP affiliate
must offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the
general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under
the procedures described below.
•
its ownership in the restricted business consists solely of a non-controlling equity interest.
For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant
GP affiliate.
The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP
Group, other than those engaged in by the WPP Group at closing of our initial public offering, may not exceed $75 million. For
purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will
be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be
acquired.
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If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market
value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired,
then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a
restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business
constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first
and then offer us the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph,
"restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restriction
summarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good
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.
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Board Representation and Observation Rights Agreement
Effective on March 2, 2017 in connection with the closing of the issuance of the Preferred Units, we entered into the Board
Observation and Representation Rights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant
to the Board Rights Agreement, Blackstone appoints one member to serve on the Board of Directors of GP Natural Resource
Partners LLC and also appoints one observer to attend meetings of the Board. Blackstone's rights to appoint a member of the Board
and an observer will terminate at such time as Blackstone, together with their affiliates, no longer own at least 20% of the total
number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the
"Minimum Preferred Unit Threshold"). Following the time that Blackstone (and their affiliates) no longer own the Minimum
Preferred Unit Threshold and until such time as GoldenTree (together with their affiliates) no longer own the Minimum Preferred
Unit Threshold, GoldenTree shall have the one-time option to appoint either one person to serve as a member of the Board or one
person to serve as a Board observer. To the extent GoldenTree elects to appoint a Board member and later remove such Board
member, GoldenTree may then elect to appoint a Board observer. For more information on the Preferred Units, including the rights
of the holders thereof, see "Item 8. Financial Statements and Supplementary Data—Note 5. Class A Convertible Preferred Units
and Warrants" elsewhere in this Annual Report on Form 10-K.
Transactions with Cline Group and Affiliates
On May 9, 2017, Adena Minerals, LLC (“Adena”), an affiliate of Christopher Cline (“Cline”) sold its 31% limited partner
interest in our general partner to Great Northern Properties Limited Partnership and WPPLP (the “Adena Sale”). In connection
with the Adena Sale, on May 9, 2017, the Investor Rights Agreement effective as of January 4, 2007 by and among Adena, NRP
GP, GP LLC, and Robertson Coal Management (the “Investor Rights Agreement”) terminated pursuant to its terms. Also on May
9, 2017, the Restricted Business Contribution Agreement effective as of January 4, 2007, by and among Christopher Cline, Foresight
Reserves LP, Adena, NRP, NRP GP, and NRP (Operating) LLC (the “RBCA”) terminated pursuant to the terms thereof. In addition,
the rights of Adena and its affiliates under the Partnership’s partnership agreement are no longer in effect as a result of the Adena
Sale (other than customary rights to indemnification).
As a result of the Adena Sale, we no longer consider Cline or his affiliates, including Foresight Energy, affiliates of NRP.
For a summary of revenues that we have derived from the Cline relationship, including Foresight Energy LP, see "Item 8. "Item
8. Financial Statements and Supplementary Data—Note 15. Related Party Transactions—Cline Affiliates and Foresight Energy"
elsewhere in this Annual Report on Form 10-K..
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."
142
NRP’s business strategy does not, and is not expected to, include:
• The ownership of equity interests in companies involved in the mining or extraction of coal.
•
•
Investments that do not generate "qualifying income" for a publicly traded partnership under U.S. tax regulations.
Investments outside of North America.
• Midstream or refining businesses that do not involve hard extracted minerals, including the gathering, processing,
fractionation, refining, storage or transportation of oil, natural gas or natural gas liquids.
The businesses and investments described in this paragraph are referred to as the "Non-NRP Businesses."
It is acknowledged that neither Quintana Capital nor Mr. Robertson will have any obligation to offer investments relating
to Non-NRP Businesses to NRP, and that NRP will not have any obligation to refrain from pursuing a Non-NRP Business if there
is a change in its business strategy.
For so long as Corbin Robertson, Jr. remains both an affiliate of Quintana Capital and an executive officer or director of
NRP or an affiliate of its general partner, before making an investment in an NRP Business, Quintana Capital has agreed to adhere
to the following procedures:
• Quintana Capital will first offer such opportunity in its entirety to NRP. NRP may elect to pursue such investment wholly
for its own account, to pursue the opportunity jointly with Quintana Capital or not to pursue such opportunity.
•
If NRP elects not to pursue an NRP Business investment opportunity, Quintana Capital may pursue the investment for
its own account on similar terms.
• NRP will undertake to advise Quintana Capital of its decision regarding a potential investment opportunity within 10
business days of the identification of such opportunity to the Conflicts Committee.
If the opportunity relates to the acquisition of a Shared Business, NRP and Quintana Capital will adhere to the following
procedures:
•
•
If the opportunity is generated by individuals other than Mr. Robertson, the opportunity will belong to the entity for
which those individuals are working.
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.
A fund controlled by Quintana Capital owns an interest in Corsa Coal Corp, a coal mining company traded on the TSX
Venture Exchange that is one of our lessees in Tennessee. Corbin J. Robertson, III, one of our directors, was Chairman of the Board
of Corsa through May 10, 2017. In addition, in May 2017, a subsidiary of Alpha Natural Resources assigned two coal leases with
us to Quinwood Coal Partners LP ("Quinwood"), an entity controlled by Mr. Robertson, III. In connection with this lease assignment,
Quinwood forfeited the historical recoupable balance related to this property.
For more information on our relationship with Corsa Coal and Quinwood, see "Item 8. Financial Statements and
Supplementary Data—Note 15. Related Party Transactions—Quintana Capital Group GP, Ltd." and —Quinwood Coal Company
Royalty.
Office Building in Huntington, West Virginia
We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The
initial 10-year term of the lease expired at the end of 2018. On January 1, 2019 we entered into a new lease on the building for a
five-year base term, with five additional five-year renewal options. During the years ended December 31, 2018 and 2017, we paid
approximately $0.6 million in rent each year to Western Pocahontas under the lease.
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Relationship with Cadence Bank, N.A.
Paul B. Murphy, Jr. one of the members of the Board of Directors of GP Natural Resource Partners LLC, is the Chairman
of Cadence Bank, N.A., which is a lender under NRP Operating’s revolving credit facility and has received customary fees and
interest payments in connection therewith. During the years ended December 31, 2018 and 2017, we paid approximately $0.6
million and $0.3 million, respectively in interest and fees under the credit facility to Cadence Bank, N.A.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its
affiliates (including the WPP Group) on the one hand, and our partnership and our limited partners, on the other hand. The directors
and officers of GP Natural Resource Partners LLC have duties to manage GP Natural Resource Partners LLC and our general
partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage our partnership in a manner
beneficial to us and our unitholders. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware
Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary
duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership
agreement contains various provisions modifying the fiduciary duties that would otherwise be owed by our general partner with
contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Our partnership
agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability
standards, might constitute breaches of fiduciary duty under applicable Delaware law.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other
partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval
of the conflicts committee of the Board of Directors of our general partner of such resolution. The partnership agreement contains
provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving
conflicts of interest.
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.
144
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding
such matters as:
•
•
•
•
•
amount and timing of asset purchases and sales;
cash expenditures;
borrowings;
the issuance of additional common units; and
the creation, reduction or increase of reserves in any quarter.
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the
unitholders, including borrowings that have the purpose or effect of enabling our general partner to receive distributions.
For example, in the event we have not generated sufficient cash from our operations to pay the quarterly distribution on our
common units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding
common units.
The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.
Our general partner and its affiliates may not borrow funds from us or our subsidiaries.
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.
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Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-
length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided
these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual
arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts
and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length
negotiations.
All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and
its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our
general partner or its affiliates to enter into any contracts of this kind.
We may not choose to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent auditors and others who have performed services for us in the past were retained by our general
partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent
auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform
services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in
the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of
common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law
has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
Our general partner’s affiliates may compete with us.
The partnership agreement provides that our general partner is restricted from engaging in any business activities other than
those incidental to its ownership of interests in us. Except as provided in our partnership agreement and the Omnibus Agreement,
affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us.
The Conflicts Committee Charter is available upon request.
Director Independence
For a discussion of the independence of the members of the Board of Directors of our managing general partner under
applicable standards, see "Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance
—Corporate Governance—Independence of Directors," which is incorporated by reference into this Item 13.
Review, Approval or Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner and its affiliates (including the WPP Group)
on the one hand, and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential
conflict is addressed as described under "—Conflicts of Interest."
Pursuant to our Code of Business Conduct and Ethics, conflicts of interest are prohibited as a matter of policy, except under
guidelines approved by the Board and as provided in the Omnibus Agreement and our partnership agreement. For the years ended
December 31, 2018 and 2017, 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 2018 and 2017. 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)
All Other Fees (3)
2018
2017
$
957,272
$
1,049,905
501,426
—
772,449
1,820
(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.
(3) All other fees include the subscription to EY Online research tool.
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 management’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.
148
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.
149
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (2) Financial Statements and Schedules
See "Item 8. Financial Statements and Supplementary Data. "
(a)(3) Ciner Wyoming LLC Financial Statements
The financial statements of Ciner Wyoming LLC required pursuant to Rule 3-09 of Regulation S-X are included in this filing
as Exhibit 99.1.
(a)(4) Exhibits
Exhibit
Number
2.1
2.2
3.1
3.2
3.3
3.4
3.5
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Description
Purchase Agreement, dated as of January 23, 2013, by and among Anadarko Holding Company, Big Island Trona
Company, NRP Trona LLC and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to Current Report
on Form 8-K filed on January 25, 2013).
Purchase and Sale Agreement dated as of November 16, 2018, by and between NRP (Operating) LLC and VantaCore
Intermediate Holdings LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on
November 20, 2018).
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).
150
Exhibit
Number
4.8
4.9
4.10
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
10.1
10.2
10.3
10.4
Description
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).
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 March 2, 2017, 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 4.3 to Current
Report on Form 8-K filed on March 6, 2017).
Form of 10.500% Senior Notes due 2018 (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).
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).
151
Exhibit
Number
10.5
10.6
10.7
10.8
10.9
10.10
10.11+
10.12+
10.13+
10.14+
10.15+
10.16+
Description
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).
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).
Preferred Unit and Warrant Purchase Agreement, dated as of February 22, 2017, by and among Natural Resource
Partners L.P. and the Purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form
8-K filed on March 6, 2017.
Exchange and Purchase Agreement, dated as of February 22, 2017, by and among Natural Resource Partners L.P.,
NRP Finance Corporation and the Consenting Holders named therein (incorporated by reference to Exhibit 10.4 to
Current Report on Form 8-K filed on March 6, 2017.
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)
Settlement Agreement dated October 19, 2018 by and among WPP LLC and Foresight Energy LP (incorporated by
reference to Exhibit 10.1 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2018 filed by
Foresight Energy LP on November 7, 2018).
Natural Resource Partners Second Amended and Restated Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.1 to Current Report on Form 8-K filed on January 17, 2008).
Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.4 to Annual Report on Form 10-K for
the year ended December 31, 2007).
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).
Employment Agreement dated August 16, 2017, between Quintana Minerals Corporation and Wyatt L. Hogan
(incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on November 8, 2017).
10.17*+
General Release of Claims between Quintana Minerals Corporation and Perry W. Donahoo.
21.1*
23.1*
23.2*
31.1*
31.2*
32.1**
32.2**
95.1*
99.1*
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.
Mine Safety Disclosure.
Financial Statements of Ciner Wyoming LLC as of December 31, 2018 and 2017 and for the years ended
December 31, 2018, 2017 and 2016.
152
Exhibit
Number
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Labels Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
Description
*
**
+
Filed herewith
Furnished herewith
Management compensatory plan or arrangement
153
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 7, 2019
Date: March 7, 2019
Date: March 7, 2019
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:
By:
/s/ CHRISTOPHER J. ZOLAS
Christopher J. Zolas
Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/s/ JENNIFER L. ODINET
Jennifer L. Odinet
Chief Accounting Officer
(Principal Accounting Officer)
154
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 7, 2019
Date: March 7, 2019
Date: March 7, 2019
Date: March 7, 2019
Date: March 7, 2019
Date: March 7, 2019
Date: March 7, 2019
Date: March 7, 2019
Date: March 7, 2019
/s/ GALDINO J. CLARO
Galdino J. Claro
Director
/s/ RUSSELL D. GORDY
Russell D. Gordy
Director
Jasvinder S. Khaira
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
155
Exhibit 10.17
GENERAL RELEASE OF CLAIMS
This GENERAL RELEASE OF CLAIMS (this “Agreement”) is entered into by Perry
Donahoo (“Employee”) and is that certain Release defined in Section 6 of the Employment
Agreement effective as of October 25, 2017 by and between Quintana Minerals Corporation (the
“Company”) and Employee (the “Employment Agreement”). Capitalized terms not defined herein
have the meaning given to them in the Employment Agreement.
WHEREAS, on December 11, 2018 (the “Closing Date”), VantaCore Intermediate Holding,
LLC has purchased all of the Equity Interests (as defined in the Purchase and Sale Agreement) in
certain entities, including VantaCore Partners LLC, (the Transaction”), as contemplated by that
certain Purchase and Sale Agreement dated as of November 16, 2018 by and between VantaCore
Intermediate Holding, LLC and NRP (Operating) LLC (the “Purchase and Sale Agreement”);
WHEREAS, Employee’s employment or other service relationship with or for the benefit
of the Company has ended as of the day immediately preceding the Closing Date; and
WHEREAS, Employee and the Company wish to resolve any and all claims Employee has
or may have against the Company or any other Company Party (as defined below).
NOW THEREFORE, in consideration of the promises and benefits set forth herein, and for
other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged
by the parties hereto, the Company and Employee agree as follows:
1. Severance Benefits. Employee acknowledges and agrees that the last day of
Employee’s employment with the Company was December 10, 2018 (the “Separation Date”) and
the Company will pay Employee a lump sum amount of one million eight hundred sixty-seven
thousand three hundred fifty-seven dollars ($1,867,357) on or before the date that is one business
day after the Closing Date. Additionally, if (a) Employee executes this Agreement on or after the
Separation Date and returns it to the Company, care of Sarah Watson at 1201 Louisiana Street 34th
Floor Houston, Texas 77002 (swatson@nrplp.com) so that it is received by Ms. Watson no later
than 11:59 p.m. Houston, Texas time on January 24, 2019, (b) does not exercise his revocation rights
pursuant to Section 11 below, and (c) abides by Employee’s continuing obligations under the
Employment Agreement (including the terms of Section 5 thereof), then the Company will –
(a) provide Employee the payments and benefits set forth in Section 4(d) of the
Employment Agreement, subject to the terms of the Employment Agreement; and
(b) waive Employee’s continuing obligations under Sections 5(c) and 5(d) of the
Employment Agreement effective on the expiration of the Release Revocation Period.
The payments and benefits set forth in clauses (a) and (b) above are referred to herein collectively
as the “Severance Benefits.”
2. Satisfaction of All Leaves and Payment Amounts; Prior Rights and
Obligations. In entering into this Agreement, Employee expressly acknowledges and agrees that
Employee has received all leaves (paid and unpaid) to which Employee was entitled during
Employee’s employment with the Company and any other Company Party (as defined below) and
Employee has received all wages, bonuses, and other compensation, been provided all benefits,
been afforded all rights and been paid all sums that Employee is owed and has been owed or could
ever be owed by the Company and any other Company Party as of the date that Employee executes
this Agreement (the “Signing Date”). For the avoidance of doubt, Employee acknowledges and
agrees that Employee had no right to the Severance Benefits (or any portions thereof) but for
Employee’s entry into this Agreement.
3. Release of Liability for Claims.
(a)
In consideration of Employee’s receipt of the Severance Benefits (and any
portion thereof), Employee hereby forever releases, discharges and acquits the Company, Western
Pocahontas Properties Limited Partnership, Natural Resource Partners L.P., their respective
affiliates, and each of the foregoing entities’ respective past, present and future subsidiaries,
affiliates, stockholders, members, partners, directors, officers, managers, insurers, employees,
agents, attorneys, heirs, predecessors, successors and representatives in their personal and
representative capacities, as well as all employee benefit plans maintained by any of the foregoing
and all fiduciaries and administrators of any such plans, in their personal and representative
capacities (collectively, the “Company Parties”), from liability for, and Employee hereby waives,
any and all claims, damages, or causes of action of any kind related to Employee’s employment
with any Company Party, the termination of such employment, and any other acts or omissions
related to any matter occurring or existing on or prior to the Signing Date, including (i) any alleged
violation through such date of: (A) any federal, state or local anti-discrimination or anti-retaliation
law, including the Age Discrimination in Employment Act of 1967, as amended (including as
amended by the Older Workers Benefit Protection Act), Title VII of the Civil Rights Act of 1964,
as amended, the Civil Rights Act of 1991, as amended, and Sections 1981 through 1988 of Title 42
of the United States Code, as amended; and the Americans with Disabilities Act of 1990, as amended;
(B) the Employee Retirement Income Security Act of 1974, as amended (“ERISA”); (C) the
Immigration Reform Control Act, as amended; (D) the Occupational Safety and Health Act, as
amended; (E) the Family and Medical Leave Act of 1993; (F) any federal, state or local wage and
hour law; (G) any other local, state or federal law, regulation or ordinance; or (H) any public policy,
contract, tort, or common law claim or claim for fiduciary duty or breach thereof or claim for fraud
or misrepresentation or fraud of any kind; (ii) any allegation for costs, fees, or other expenses
including attorneys’ fees incurred in, or with respect to, a Released Claim; (iii) any and all rights,
benefits or claims Employee may have under any retention, change in control, bonus, long term
incentive or severance plan or policy of any Company Party or any retention, change in control,
bonus, long term incentive or severance-related agreement that Employee may have or have had
with any Company Party other than the rights to the Severance Benefits described herein; (iv) any
and all rights, benefits or claims Employee may have under any employment contract (including
the Employment Agreement), equity-based compensation plan or arrangement (including the LTIP),
incentive compensation plan, limited liability company agreements, and any other agreement; and
(v) any claim for compensation or benefits of any kind not expressly set forth in this Agreement
(collectively, the “Released Claims”). In no event shall the Released Claims include (x) any claim
that first arises after the Signing Date (y) any claim to vested benefits under an employee benefit
plan governed by ERISA, or (z) any claim arising after the Signing Date under any equity award
agreement respecting Employee’s equity ownership in the Company or any other Company Party
that survives the Employee’s Separation Date. This Agreement is not intended to indicate that any
such claims exist or that, if they do exist, they are meritorious. Rather, Employee is simply agreeing
that, in exchange for the Severance Benefits, any and all potential claims of this nature that Employee
may have against the Company Parties, regardless of whether they actually exist, are expressly
settled, compromised and waived. THIS RELEASE INCLUDES MATTERS ATTRIBUTABLE
TO THE SOLE OR PARTIAL NEGLIGENCE (WHETHER GROSS OR SIMPLE) OR
OTHER FAULT, INCLUDING STRICT LIABILITY, OF ANY OF THE COMPANY
PARTIES.
(b)
Notwithstanding this release of liability, nothing in this Agreement prevents
Employee from filing any non-legally waivable claim (including a challenge to the validity of this
Agreement) with the Equal Employment Opportunity Commission (“EEOC”) or comparable state
or local agency or participating in (or cooperating with) any investigation or proceeding conducted
by the EEOC or comparable state or local agency or cooperating with such agency; however,
Employee understands and agrees that Employee is waiving any and all rights to recover any
monetary or personal relief or recovery as a result of such EEOC or comparable state or local agency
or proceeding or subsequent legal actions.
(c)
Nothing in this Agreement shall prohibit or restrict Employee from lawfully
(i) initiating communications directly with, cooperating with, providing information to, causing
information to be provided to, or otherwise assisting in an investigation by any Governmental
Authorities regarding a possible violation of any law; (ii) responding to any inquiry or legal process
directed to Employee individually from any such Governmental Authorities; (iii) testifying,
participating or otherwise assisting in an action or proceeding by any such Governmental Authorities
relating to a possible violation of law; or (iv) making any other disclosures that are protected under
the whistleblower provisions of any applicable law. Additionally, pursuant to the federal Defend
Trade Secrets Act of 2016, Employee shall not be held criminally or civilly liable under any federal
or state trade secret law for the disclosure of a trade secret that: (i) is made (A) in confidence to a
federal, state, or local government official, either directly or indirectly, or to an attorney; and (B)
solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made to
Employee’s attorney in relation to a lawsuit for retaliation against Employee for reporting a suspected
violation of law; or (iii) is made in a complaint or other document filed in a lawsuit or other
proceeding, if such filing is made under seal. Nothing in this Agreement requires Employee to obtain
prior authorization from the Company before engaging in any conduct described in this paragraph,
or to notify the Company that Employee has engaged in any such conduct.
(d)
For the avoidance of doubt, nothing herein waives Employee’s future rights
to indemnification or to the benefits of any directors and officers insurance, to the extent such rights
and benefits exist pursuant to the terms of applicable bylaws, agreements or applicable plans, as
each may be amended from time to time.
4. Representation About Claims. Employee represents and warrants that, as of the
Signing Date, Employee has not filed any claims, complaints, charges, or lawsuits against any of
the Company Parties with any governmental agency or with any state or federal court or arbitrator
for or with respect to a matter, claim, or incident that occurred or arose out of one or more occurrences
that took place on or prior to the Signing Date. Employee further represents and warrants that
Employee has made no assignment, sale, delivery, transfer or conveyance of any rights Employee
has asserted or may have against any of the Company Parties with respect to any Released Claim.
5. Employee’s Acknowledgments. By executing and delivering this Agreement,
Employee expressly acknowledges that:
(a) Employee has carefully read this Agreement and has had sufficient time
(and at least 45 days) to consider this Agreement before signing it and delivering it to the
Company;
(b) Employee has been advised, and hereby is advised in writing, to discuss this
Agreement with an attorney of Employee’s choice and Employee has had adequate
opportunity to do so prior to executing this Agreement;
(c) Employee fully understands the final and binding effect of this Agreement;
the only promises made to Employee to sign this Agreement are those stated herein; and
Employee is signing this Agreement knowingly, voluntarily and of Employee’s own free
will, and understands and agrees to each of the terms of this Agreement;
(d) The only matters relied upon by Employee and causing Employee to sign
this Agreement are the provisions set forth in writing within the four corners of this
Agreement;
(e) Employee would not otherwise have been entitled to the Severance Benefits,
or any portion thereof, but for Employee’s agreement to be bound by the terms of this
Agreement;
(f) No Company Party has provided any tax or legal advice regarding this
Agreement and Employee has had the opportunity to receive sufficient tax and legal advice
from advisors of Employee’s own choosing such that Employee enters into this Agreement
with full understanding of the tax and legal implications thereof; and
(g) Employee has been provided with, and attached to this Agreement as Exhibit
A is, a listing of: (i) titles and ages of all individuals selected for participation in the program
pursuant to which Employee is being offered this Agreement; (ii) titles and ages of all
individuals in the same decisional unit who were not selected for participation in the program;
and (iii) information about the unit affected by the program, including any eligibility factors
for such program and any time limits applicable to such program.
6. Third-Party Beneficiaries. Employee expressly acknowledges and agrees that
each Company Party that is not a signatory to this Agreement shall be a third-party beneficiary of
Employee’s release of claims and representations in Sections 2-5 and 9 hereof.
7. Severability. Any term or provision of this Agreement (or part thereof) that renders
such term or provision (or part thereof) or any other term or provision hereof (or part thereof) invalid
or unenforceable in any respect shall be severable and shall be modified or severed to the extent
necessary to avoid rendering such term or provision (or part thereof) invalid or unenforceable, and
such modification or severance shall be accomplished in the manner that most nearly preserves the
benefit of the bargain set forth in the Employment Agreement and hereunder.
8. Withholding of Taxes and Other Deductions. Employee acknowledges that the
Company may withhold from the Severance Benefits all federal, state, local, and other taxes and
withholdings as may be required by any law or governmental regulation or ruling.
9. Return of Property. Employee represents and warrants that Employee has
returned to the Company all property belonging to the Company or any other Company Party,
including all computer files, electronically stored information and other materials provided to him
by the Company or any other Company Party in the course of Employee’s employment with the
Company and Employee further represents and warrants that Employee has not maintained a copy
of any such materials in any form.
10. Further Assurances. In signing below, Employee expressly acknowledges the
enforceability, and continued effectiveness of Section 5 of the Employment Agreement and promises
to abide by those terms of the Employment Agreement to the extent such terms are not waived by
the Company pursuant to Section 1.
11. Revocation Right. Notwithstanding the initial effectiveness of this Agreement,
Employee may revoke the delivery (and therefore the effectiveness) of this Agreement within the
seven-day period beginning on the Signing Date (such seven day period being referred to herein as
the “Release Revocation Period”). To be effective, such revocation must be in writing signed
Employee and must be received by Sarah Watson at 1201 Louisiana Street 34th Floor Houston,
Texas 77002 (swatson@nrplp.com) before 11:59 p.m., Houston, Texas time, on the last day of the
Release Revocation Period. If an effective revocation is delivered in the foregoing manner and
timeframe, no Severance Benefits shall be provided and this Agreement shall be null and void;
provided, however, that the provisions of Sections 2, 4, 9 and 10 shall remain in full force and effect
and shall not be affected by any such revocation.
12. Employment Agreement. This Agreement shall be subject to the provisions of
Sections 8, 10, 11, 15, 16 and 18 of the Employment Agreement, which provisions are hereby
incorporated by reference as a part of this Agreement.
[Remainder of Page Intentionally Blank;
Signature Page Follows]
IN WITNESS WHEREOF, the parties have executed this Agreement as of the date set
forth below, effective for all purposes as provided above.
EMPLOYEE
/s/ Perry Donahoo
Perry Donahoo
Date: January 8, 2019
COMPANY
Quintana Minerals Corporation
By: /s/ J. Rich Grobleben
Name: J. Rich Grobleben
Title: Vice President
Date: December 11, 2018
Exhibit 21.1
List of Subsidiaries of Natural Resource Partners L.P.
NRP (Operating) LLC
NRP Oil and Gas LLC
NRP Finance Corporation
WPP LLC
ACIN LLC
WBRD LLC
Hod LLC
Shepard Boone Coal Company LLC
Gatling Mineral, LLC
Independence Land Company, LLC
Williamson Transport, LLC
Little River Transport, LLC
Rivervista Mining, LLC
Deepwater Transportation, LLC
NRP Trona LLC
BRP LLC (51% interest)
CoVal Leasing Company, LLC (51% interest)
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
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 7, 2019, 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, 2018.
/s/ Ernst & Young LLP
Houston, Texas
March 7, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statements on Form S-3 (Nos. 333-217205 and 333-187883) and
Form S-8 (No. 333-222970) of Natural Resource Partners L.P., of our report dated March 7, 2019, relating to the financial statements
of Ciner Wyoming LLC as of December 31, 2018 and 2017, and for the three years in the period ended December 31, 2018,
appearing in this Annual Report on Form 10-K of Natural Resource Partners L.P. for the year ended December 31, 2018.
Exhibit 23.2
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 7, 2019
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 7, 2019
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 7, 2019
CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
Exhibit 32.1
In connection with the accompanying report on Form 10-K for the year ended December 31, 2018 filed with the Securities
and Exchange Commission on the date hereof (the “Report”), I, Corbin J. Robertson, Jr., Chief Executive Officer of GP Natural
Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the “Company”), hereby
certify, to my knowledge, that:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
By:
/s/ Corbin J. Robertson, Jr.
Corbin J. Robertson, Jr.
Chief Executive Officer
Date: March 7, 2019
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, 2018 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 7, 2019
MINE SAFETY DISCLOSURE
Exhibit 95.1
We owned VantaCore Partners LLC, a construction aggregates business, through December 11, 2018. Effective
December 11, 2018, we sold VantaCore Partners LLC to an unaffiliated third party. These mining operations are subject to
regulation by the Federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of
1977 (the “Mine Act”). We have disclosed below information regarding certain citations and orders issued by MSHA and
related assessments and legal actions with respect to these mining operations for the period from January 1, 2018 to December
11, 2018. In evaluating the below information regarding mine safety and health, investors should take into account factors such
as: (i) the number of citations and orders will vary depending on the size of a mine; (ii) the number of citations issued will vary
from inspector to inspector and mine to mine; and (iii) citations and orders can be contested and appealed, and in that process
are often reduced in severity and amount, and are sometimes dismissed or vacated. The tables below do not include any orders
or citations issued to independent contractors at our mines.
Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires
issuers to include in periodic reports filed with the Securities and Exchange Commission (“SEC”) certain information relating
to citations and orders for violations of standards under the Mine Act. The following tables disclose information required under
the Dodd-Frank Act for the period from January 1, 2018 to December 11, 2018.
Mine Name / MSHA Identification Number
Section 104
S&S
Citations(1)
Section 104(b)
Orders (2)
Section 104(d)
Citations and
Orders (3)
Section 110(b)
(2)
Violations (4)
Section 107(a)
Orders (5)
Total Dollar
Value of MSHA
Assessments
Proposed (6)
Winn Materials-Clarksville/40-03094
Winn Materials of KY-Grand Rivers/
15-19561
Laurel Aggregates/36-08891
Southern Aggregates/Plant 7.2/16-01551
Southern Aggregates/Plant 9/16-01536
Southern Aggregates/Plant 10/16-01571
Southern Aggregates/Plant 12/16-01546
Southern Aggregates/Plant 14/16-01578
Southern Aggregates/Plant 16/16-01563
Southern Aggregates/Plant 20/16-01580
3
1
1
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
$1,071
$118
$2,652
$3,069
$236
$906
$250
$0
$590
$0
(1) Mine Act section 104 S&S citations shown above are for alleged violations of mandatory health or safety standards that could significantly and
substantially contribute to a mine health and safety hazard. It should be noted that, for purposes of this table, S&S citations that are included in another
column, such as Section 104(d) citations, are not also included as Section 104 S&S citations in this column.
(2) Mine Act section 104(b) orders are for alleged failures to totally abate a citation within the time period specified in the citation.
(3) Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence)
to comply with mandatory health or safety standards.
(4) Mine Act section 110(b)(2) violations are for an alleged “flagrant” failure (i.e., reckless or repeated) to make reasonable efforts to eliminate a known
violation of a mandatory safety or health standard that substantially and proximately caused, or reasonably could have been expected to cause, death
or serious bodily injury.
(5) Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or serious physical harm
before such condition or practice can be abated and result in orders of immediate withdrawal from the area of the mine affected by the condition.
(6) Amounts shown include assessments proposed by MSHA during the twelve-month period of January 1, 2018 to December 11, 2018 on all citations
and orders, including those citations and orders that are not required to be included within the above chart.
(7) No. of vacated citations during 2018: Laurel Aggregates-Five (5) vacated 104(a) citations; Southern Aggregates-One (1) vacated 104(a) citations.
Mine Name / MSHA Identification Number
Winn Materials-Clarksville/40-03094
Winn Materials of KY-Grand Rivers/15-19561
Laurel Aggregates/36-08891
Southern Aggregates/Plant 7.2/16-01551
Southern Aggregates/Plant 9/16-01536
Southern Aggregates/Plant 11/16-01571
Southern Aggregates/Plant 12/16-01546
Southern Aggregates/Plant 14/16-01578
Southern Aggregates/Plant 16/16-01563
Southern Aggregates/Plant 20/16-01580
Total Number of
Mining Related
Fatalities
Received Notice of
Pattern of
Violations Under
Section 104(e)
(yes/no) (1)
Legal Actions
Pending as of Last
Day of Period
Legal Actions
Initiated During
Period
Legal Actions
Resolved During
Period
0
0
0
0
0
0
0
0
0
0
N
N
N
N
N
N
N
N
N
N
0
0
0
2
0
0
0
0
0
0
1
0
1
1
0
0
0
0
1
0
1
0
1
0
0
0
1
0
1
0
(1) Mine Act section 104(e) written notices are for an alleged pattern of violations of mandatory health or safety standards that could significantly and
substantially contribute to a mine safety or health hazard.
The number of legal actions pending before the Federal Mine Safety and Health Review Commission as of December 11,
2018, that fall into each of the following categories is as follows:
Mine Name / MSHA Identification Number
Contests of
Citations and
Orders
Contests of
Proposed
Penalties
Complaints for
Compensation
Complaints of
Discharge/
Discrimination/
Interference
Applications for
Temporary
Relief
Appeals of
Judges Rulings
Winn Materials-Clarksville/40-03094
Winn Materials of KY-Grand Rivers/
15-19561
Laurel Aggregates/36-08891
Southern Aggregates/Plant 7.2/16-01551
Southern Aggregates/Plant 9/16-01536
Southern Aggregates/Plant 10/16-01571
Southern Aggregates/Plant 12/16-01546
Southern Aggregates/Plant 14/16-01578
Southern Aggregates/Plant 16/16-01563
Southern Aggregates/Plant 20/16-01580
0
0
0
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
This page is intentionally left blank
Exhibit 99.1
Ciner Wyoming LLC
(A Majority-Owned Subsidiary of Ciner Resources LP)
Financial Statements as of December 31, 2018 and 2017 and for the Years Ended
December 31, 2018, 2017, and 2016, 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, 2018 AND 2017
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED
DECEMBER 31, 2018, 2017, AND 2016
STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 2018, 2017, AND 2016
STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016
NOTES TO THE FINANCIAL STATEMENTS
Page
Number
3
4
5
6
7
8
2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ciner Wyoming LLC (“the Company”) as of December 31, 2018 and 2017,
and the related statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years
in the period ended December 31, 2018 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, 2018 and
2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in
conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not
required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits,
we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an
opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due
to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 7, 2019
We have served as the Company’s auditor since 2008.
3
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
BALANCE SHEETS
AS OF DECEMBER 31, 2018 AND 2017
(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 loss
Total members' equity
2018
2017
$
$
7,124
70,359
36,870
22,275
1,452
26,749
98,512
34,186
19,793
1,193
138,080
180,433
226,411
208,369
26,332
19,633
$
390,823
$
408,435
$
— $
17,478
2,843
43,691
64,012
99,000
10,921
11,400
14,426
3,084
27,309
56,219
138,000
10,401
173,933
204,620
114,434
109,947
(7,491)
107,622
103,402
(7,209)
216,890
203,815
TOTAL LIABILITIES AND MEMBERS' EQUITY
$
390,823
$
408,435
See notes to financial statements.
4
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016
(In thousands of dollars)
SALES - AFFILIATES
SALES - OTHERS
Total net sales
COST OF PRODUCTS SOLD
FREIGHT COSTS
Total cost of products sold
GROSS PROFIT
2018
2017
2016
$
253,345
233,414
486,759
243,562
139,144
382,706
104,053
$
$
304,497
192,843
497,340
237,445
145,693
271,274
203,913
475,187
241,353
119,602
383,138
360,955
114,202
114,232
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES
17,698
16,520
17,575
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS
LOSS ON DISPOSAL OF ASSETS, NET
LITIGATION SETTLEMENT GAIN
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest income
Interest expense
Other income (expense), net
Total other income (expense)
NET INCOME
OTHER COMPREHENSIVE INCOME (LOSS)
2,106
—
(27,500)
1,543
1,569
—
1,258
271
—
111,749
94,570
95,128
1,871
(5,058)
(205)
1,663
(4,531)
(179)
48
(3,550)
(30)
(3,392)
(3,047)
(3,532)
108,357
91,523
91,596
Income (loss) on derivative financial instruments
(282)
(3,930)
912
COMPREHENSIVE INCOME
See notes to financial statements.
$
108,075
$
87,593
$
92,508
5
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF MEMBERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016
(In thousands of dollars)
Ciner
Resources LP
Natural
Resource
Partners LP
Accumulated
Other
Comprehensive
Income (Loss)
Total
Members'
Equity
$
$
$
$
113,681
$
109,224
$
(4,191) $
218,714
46,714
(48,450)
—
44,882
(46,550)
—
—
—
912
91,596
(95,000)
912
111,945
$
107,556
$
(3,279) $
216,222
46,677
(51,000)
—
44,846
(49,000)
—
—
—
(3,930)
91,523
(100,000)
(3,930)
107,622
$
103,402
$
(7,209) $
203,815
55,262
(48,450)
—
53,095
(46,550)
—
—
—
(282)
108,357
(95,000)
(282)
114,434
$
109,947
$
(7,491) $
216,890
Balance at December 31, 2015
Allocation of net income
Capital distribution to members
Other comprehensive income (loss)
Balance at December 31, 2016
Allocation of net income
Capital distribution to members
Other comprehensive income (loss)
Balance at December 31, 2017
Allocation of net income
Capital distribution to members
Other comprehensive income (loss)
Balance at December 31, 2018
See notes to financial statements.
6
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
108,357
$
91,523
$
91,596
2018
2017
2016
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
27,996
—
448
28,152
(2,683)
(3,025)
(228)
2,350
4,067
(240)
26,827
1,569
299
(36,691)
(792)
498
(189)
1,679
(1,124)
(1,124)
25,697
271
422
2,716
394
6,968
524
1,131
3,618
(426)
Net cash provided by operating activities
165,194
82,475
132,911
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on revolving credit facility
Repayments on revolving credit facility
Repayments on other long-term debt
Debt issuance costs
Cash distribution to members
(39,419)
(24,757)
(25,341)
(39,419)
(24,757)
(25,341)
104,000
(143,000)
(11,400)
—
(95,000)
88,500
(28,500)
(8,600)
(1,097)
(100,000)
15,000
(27,000)
—
—
(95,000)
Net cash used in financing activities
(145,400)
(49,697)
(107,000)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(19,625)
8,021
570
CASH AND CASH EQUIVALENTS:
Beginning of year
End of year
SUPPLEMENTAL DISLCOSURES OF CASH FLOW INFORMATION:
Interest paid during the year
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES :
Capital expenditures on account
See notes to financial statements
26,749
18,728
18,158
7,124
$
26,749
$
18,728
5,141
$
4,097
$
3,213
14,002
$
1,034
$
3,938
$
$
$
7
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
NOTES TO FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2018 AND 2017 AND FOR THE YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016
(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 73% by Ciner Wyoming
Holding Co. ("Ciner Holdings"), approximately 2% by Ciner Resource Partners LLC (our “general partner” or “Ciner
GP”) and approximately 25% 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, 2018, Ciner
Enterprises was 100% owned by WE Soda Ltd., a U.K. corporation (“WE Soda”). WE Soda is a direct wholly-owned
subsidiary of KEW Soda Ltd., a U.K. corporation (“KEW Soda”), which is a direct wholly-owned subsidiary of Akkan
Enerji ve Madencilik Anonim
irketi ("Akkan"), which is 100% owned by Turgay Ciner, the Chairman of the Ciner
Group, a Turkish conglomerate of companies engaged in energy and mining (including soda ash mining), media and
shipping markets.
On February 22, 2018, Akkan transferred its direct 100% ownership in Ciner Enterprises to KEW Soda, a UK company,
which transferred such ownership to WE Soda, a UK 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 UK.
2. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations - The Company operations consist of the mining of trona ore, which, when processed, becomes
soda ash. All our soda ash processed is sold to various domestic customers, and to Ciner Ic ve Dis Ticaret Anonim Sirketi
("CIDT") and American Natural Soda Ash Corporation ("ANSAC") which are affiliates for export sales. The Company
began selling soda ash in late 2016 to CIDT and continued into 2017. There were no sales to CIDT during the year ended
December 31, 2018, as the contract terminated in 2017. All mining and processing activities take place in one facility
located in Green River, Wyoming.
Recent Developments
Notice to Terminate Membership in ANSAC - On November 9, 2018, we were informed that Ciner Corp had delivered a
notice to terminate its membership in ANSAC, a cooperative that serves as the primary international distribution channel
for us as well as two other U.S. manufacturers of trona-based soda ash. The effective termination date is expected to be
December 31, 2021. ANSAC was our largest customer for the years ended December 31, 2018, 2017 and 2016,
accounting for 52.0%, 44.7% and 55.2%, respectively, of our net sales. Although ANSAC has been our largest customer
for the years ended December 31, 2018, 2017, and 2016, we anticipate that the impact of such termination 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 that has historically seen demand for soda
ash exceed supply of soda ash, and therefore we anticipate being able to find export customers regardless of market
conditions. Between now and the termination date, Ciner Corp will continue to have full ANSAC membership benefits
8
and services. After the termination period, Ciner Corp will sell soda ash directly into international markets that are
currently being served by ANSAC and intends to utilize the distribution network that has already been established by the
global Ciner Group. We believe by combining our volumes with Ciner Group’s soda ash exports from Turkey, our
withdrawal from ANSAC will allow us to leverage the larger, global Ciner Group soda ash operations. We expect this will
eventually lower our cost position and improve our ability to optimize our market share both domestically and
internationally. The ANSAC agreement provides that in the event an ANSAC member exits or the ANSAC cooperative is
dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the
cooperative. As of December 31, 2018, we have not recognized an asset or liability related to the exit from ANSAC as
such an amount is not currently probable or estimable.
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 date of the financial statements, and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition - On May 28, 2014 the Financial Accounting Standards Board (the “FASB”) issued Accounting
Standards Codification (“ASC”) 606, Revenue from Contracts with Customers (Topic 606), that requires companies to
recognize revenue when a customer obtains control rather than when companies have transferred substantially all risks
and rewards of a good or service. The Company adopted this ASC effective January 1, 2018, as permitted by the ASC,
using the modified retrospective method and we have not made any adjustment to opening retained earnings. The
Company has applied the provisions of this ASC and notes that our adoption of ASC 606 does not materially change the
amount or timing of revenues recognized by us, nor does it materially affect our financial position. The majority of our
revenues generated are recognized upon delivery and transfer of title to the product to our customers. The time at which
delivery and transfer of title occurs, for the majority of our contracts with customers, is the point when the product leaves
our facility, thereby rendering our performance obligation fulfilled. Additionally, the Company has made an accounting
policy election to account for shipping and handling activities as fulfillment costs.
Freight Costs - The Company includes freight costs billed to customers for shipments administered by the Company in
gross sales. The related freight costs along with cost of products sold are deducted from gross sales to determine gross
profit.
Cash and Cash Equivalents - The Company considers all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents. Cash equivalents consist primarily of money market deposit accounts.
Accounts Receivable - Accounts receivable are carried at the original invoice amount less an estimate for doubtful
receivables. We generally do not require collateral against outstanding accounts receivable. The allowance for doubtful
accounts is based on specifically identified amounts that the Company believes to be uncollectible. An additional
allowance is recorded based on certain percentages of aged receivables, which are determined based on management’s
assessment of the general financial conditions affecting the Company’s customer base. We determined that no allowance
for doubtful accounts was required against receivables from affiliates as of December 31, 2018 and 2017. If actual
collection experience changes, revisions to the allowance may be required. Accounts receivable are written off when
deemed uncollectible. Recoveries of accounts receivable previously written off are recorded when received.
9
Inventory - Inventory is carried at the lower of cost or market. Cost is determined using the first-in, first-out method for
raw material and finished goods inventory and the weighted average cost method for stores inventory. Costs include raw
materials, direct labor and manufacturing overhead. Market is based on current replacement cost for raw materials and net
realizable value for stores inventory and finished goods.
• Raw material inventory includes material, chemicals and natural resources being used in the mining and refining
process.
• Finished goods inventory is the finished product soda ash.
• Stores inventory includes parts, materials and operating supplies which are typically consumed in the production of
soda ash and currently available for future use. Inventory expected to be consumed within the year is classified as current
assets and remainder is classified as non-current assets.
Property, Plant, and Equipment - Property, plant, and equipment are stated at cost less accumulated depreciation.
Depreciation is computed over the estimated useful lives of depreciable assets, using the straight-line method. The
estimated useful lives applied to depreciable assets are as follows:
Land improvements
Depletable land
Buildings and building improvements
Computer hardware
Machinery and equipment
Furniture and fixtures
Useful Lives
10 years
15-60 years
10-30 years
3-5 years
5-20 years
10 years
The Company's policy is to evaluate property, plant, and equipment for impairment whenever events or changes in
circumstances indicate that its carrying amount may not be recoverable. An indicator of potential impairment would
include situations when the estimated future undiscounted cash flows are less than the carrying value. The amount of any
impairment then recognized would be calculated as the difference between estimated fair value and the carrying value of
the asset.
Derivative Instruments and Hedging Activities - The Company may enter into derivative contracts from time to time to
manage exposure to the risk of exchange rate changes on its foreign currency transactions, the risk of changes in natural
gas prices, and the risk of the variability in interest rates on borrowings. Gains and losses on derivative contracts
qualifying for hedge accounting are reported as a component of the underlying transactions. The Company follows hedge
accounting for its hedging activities. All derivative instruments are recorded on the balance sheet at their fair values. The
accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting
designation. The Company designates its derivatives based upon criteria established for hedge accounting under generally
accepted accounting principles. For a derivative designated as a fair value hedge, the gain or loss is recognized in
earnings in the period of change together with the offsetting gain or loss on the hedged item attributed to the risk being
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.
10
The Company has interest rate swap contracts, designated as cash flow hedges, to mitigate our exposure to possible
increases in interest rates. The swap contracts consist of four individual $12,500 swaps with an aggregate notional value
of $50,000 at December 31, 2018 and have various maturities through 2022. Our previous interest rate swap contracts,
with an aggregate notional value of $70,000 as of December 31, 2017, expired on July 18, 2018. At December 31, 2018,
it is anticipated that approximately $319 of losses currently recorded in accumulated other comprehensive income (loss)
will be reclassified into earnings within the next twelve months.
The Company has entered into financial natural gas forward contracts, designed as cash flow hedges, to mitigate volatility
in the price of the natural gas the Company consumes. These contracts generally have various maturities through 2023.
These contracts had an aggregate notional value of $41,206 and $37,087 at December 31, 2018 and December 31, 2017,
respectively. Refer to footnote 12 for details surrounding both these physical and the financial portions of our natural gas
forward contracts. At December 31, 2018, it was anticipated that $1,617 of losses currently recorded in accumulated other
comprehensive income (loss) will be reclassified into earnings within the next twelve months.
The following table presents the fair value of derivative assets and liabilities and the respective balance sheet locations as
of:
Assets
Liabilities
December 31,
2018
December 31,
2017
December 31,
2018
December 31,
2017
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Derivatives designated as
hedges:
Interest rate swap contracts -
current
Natural gas forward contracts -
current
Natural gas forward contracts -
non-current
Total derivatives designated
as hedging instruments
$
$
—
—
—
—
$
$
Accrued
Expenses
Accrued
Expenses
Other
non-
current
liabilities
—
—
—
—
$
319
Accrued
Expenses
$
1,617
Accrued
Expenses
Other
non-
current
liabilities
5,555
2
1,906
5,301
$
7,491
$
7,209
Income Tax - The Company is organized as a pass-through entity for federal and most state income tax purposes. Taxes
assessed by states on the Company are de minimis. As a result, the members are responsible for federal income taxes
based on their respective share of taxable income. Net income for financial statement purposes may differ significantly
from taxable income reportable to members as a result of differences between the tax bases and financial reporting bases
of assets and liabilities and the taxable income allocation requirements under the membership agreement.
Reclamation Costs - The Company is obligated to return the land beneath its refinery and tailings ponds to its natural
condition upon completion of operations and is required to return the land beneath its rail yard to its natural condition
upon termination of the various lease agreements.
The Company accounts for its land reclamation liability as an asset retirement obligation, which requires that obligations
associated with the retirement of a tangible long-lived asset be recorded as a liability when those obligations are incurred,
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.
11
The estimated original liability calculated in 1996 for the refinery and tailing ponds was calculated based on the estimated
useful life of the mine, which was 80 years, and on external and internal estimates as to the cost to restore the land in the
future and state regulatory requirements. During 2018, 2017 and 2016 the remaining estimated useful life of the mine was
60 years, 66 years and 67 years, respectively. In 2019, the mining reserve will be amortized over a remaining life of 59
years. 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-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 and long-term debt. The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable
and accrued expenses approximate their fair value because of the nature of such instruments. Our long-term debt and
derivative financial instruments are measured at their fair values with Level 2 inputs based on quoted market values for
similar but not identical financial instruments.
Long-Term Debt - The carrying value of our long-term debt materially reflects the fair value of our long-term debt as
rates are variable and its key terms are similar to indebtedness with similar amounts, durations and credit risks.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair
value measurement. Fair value accounting requires that these financial assets and liabilities be classified into one of the
following three categories:
• Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for an identical asset or liability in an active
market.
• Level 2-inputs to the valuation methodology include quoted prices for a similar asset or liability in an active market or
model-derived valuations in which all significant inputs are observable for substantially the full term of the asset or
liability.
• Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement of the asset
or liability.
Subsequent Events - The Company has evaluated all subsequent events through March 7, 2019, the date the financial
statements were available to be issued.
Recently Issued Accounting Standards - In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The
update amends existing standards for accounting for leases by lessees, with accounting for leases by lessors remaining
largely unchanged from current guidance. The update requires that lessees recognize a lease liability and a right of use
asset for all leases (with the exception of short-term leases) at the commencement date of the lease and disclose key
information about leasing arrangements. For leases less than 12 months, an entity is permitted to make an accounting
policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this
election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The
Company will make this election upon adoption. In preparation for the new requirements, the Company has completed its
12
evaluation of the lease agreements. The Company adopted ASC 842 effective January 1, 2019 using a modified transition
approach under which prior comparative periods will not be adjusted, as permitted by the guidance. The Company has
determined that the adoption of the new standard will not have a material impact on the balance sheet or statement of
operations because the Company has no material long term leases that are subject to ASC 842. Ciner Corp was
determined to be the ultimate lessee for rail car lease agreements under ASC 842, and the Company will continue to incur
an allocation of rent expense in relation to the use of rail cars leased by Ciner Corp.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (ASC Topic 815) - Targeted Improvements to
Accounting for Hedging Activities. This ASU aims to improve the financial reporting of hedging relationships to better
portray the economic results of an entity’s risk management activities in its financial statements. In addition, this ASU
makes certain targeted improvements to simplify the application of the existing hedge accounting guidance. This ASU is
effective for us beginning in the first quarter of 2019, with early application permitted. The Company adopted this ASU
effective January 1, 2019 and the adoption did not have a material impact to the Company’s financial statements.
3. ACCOUNTS RECEIVABLE, NET
Accounts receivable, net as of December 31, 2018 and 2017 consists of the following:
2018
2017
Trade receivables
Other receivables
Allowance for doubtful accounts
Total
4. INVENTORY
Inventory as of December 31, 2018 and 2017 consists of the following:
Raw materials
Finished goods
Stores inventory, current
Total
$
$
$
$
30,993
5,897
36,890
(20)
36,870
2018
10,867
5,112
6,296
22,275
5. PROPERTY, PLANT, AND EQUIPMENT, NET
Property, plant, and equipment as of December 31, 2018 and 2017 consists of the following:
Land and land improvements
Depletable land
Buildings and building improvements
Computer hardware
Machinery and equipment
Total
Less accumulated depreciation, depletion and amortization
Total net book value
Construction in progress
Property, plant, and equipment, net
2018
192
2,957
137,176
4,680
649,488
794,493
(614,415)
180,078
46,333
226,411
$
$
$
$
$
$
$
$
27,480
6,731
34,211
(25)
34,186
2017
10,076
3,233
6,484
19,793
2017
192
2,957
134,974
5,346
624,415
767,884
(592,045)
175,839
32,530
208,369
Depreciation, depletion and amortization expense on property, plant and equipment was $27,731, $26,418 and $25,345
for the years ended December 31, 2018, 2017 and 2016, respectively.
13
6. OTHER NON-CURRENT ASSETS
Other non-current assets as of December 31, 2018 and 2017 consists of the following:
Stores inventory, non-current
Internal-use software
Deferred financing costs and other
Total
2018
2017
$
$
19,394
6,191
747
26,332
$
$
18,589
—
1,044
19,633
In accordance with ASC 350-40, Internal Use Software, we capitalize certain internal use software development costs
associated with creating and enhancing internally developed software related to our enterprise resource planning system
that was implemented in 2018 and went live on January 1, 2019. 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. As a result, we have capitalized $6,191 of software development costs and $0 of accumulated
amortization, as an intangible asset within “other non-current assets” in the balance sheet as of December 31, 2018. 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 in the statements of operations. Amortization for these capitalized costs is
expected to be approximately $600 per year during the amortization period.
7. ACCRUED EXPENSES
Accrued expenses as of December 31, 2018 and 2017 consists of the following:
Accrued capital expenditures
Accrued employee compensation & benefits
Accrued energy costs
Accrued royalty costs
Accrued other taxes
Accrued derivatives fair values
Other accruals
Total
8. DEBT
Long-term debt as of December 31, 2018 and 2017 consists of the following:
Variable Rate Demand Revenue Bonds, principal paid October 1, 2018, interest payable
monthly, bearing an interest rate of 1.82% at December 31, 2017
Ciner Wyoming Credit Facility, unsecured principal expiring on August 1, 2022, variable
interest rate as a weighted average rate of 3.99% at December 31, 2018 and 3.08% at
December 31, 2017
Total debt
Less current portion of long-term debt
Total long-term debt
14
2018
2017
13,131
7,083
6,592
6,529
4,747
1,936
3,673
43,691
$
$
864
6,551
5,245
4,533
4,753
1,908
3,455
27,309
2018
2017
— $
11,400
99,000
99,000
—
99,000
$
138,000
149,400
11,400
138,000
$
$
$
$
Aggregate maturities required on long-term debt at December 31, 2018 are as follows:
2019
2020
2021
2022
2023
Thereafter
Total
Demand Revenue Bonds
$
$
—
—
—
99,000
—
—
99,000
On October 1, 2018 the Company fully extinguished the $11,400 Variable Rate Demand Revenue Bonds due on that day.
The Bonds were paid in full, including all accrued interest and without penalties. Additionally, the extinguishment of the
bonds relieved Ciner Wyoming of maintaining the related standby letters of credit.
Ciner Wyoming Credit Facility
On August 1, 2017, Ciner Wyoming entered into a Credit Agreement (“Ciner Wyoming Credit Facility”) with each of the
lenders listed on the respective signature pages thereof and PNC Bank, National Association, as administrative agent,
swing line lender and a Letter of Credit (“ L/C”) issuer. The Ciner Wyoming Credit Facility replaces the former Credit
Facility (“Former Ciner Wyoming Credit Facility”), dated as of July 18, 2013, by and among Ciner Wyoming, the lenders
party thereto and Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, as amended, which
was terminated on August 1, 2017 upon entry into the Ciner Wyoming Credit Facility. This arrangement was accounted
for as a modification of debt in accordance with ASC 470-50.
The Ciner Wyoming Credit Facility is a $225,000 senior unsecured revolving credit facility with a syndicate of lenders,
which will mature on the fifth anniversary of the closing date of such credit facility. The Ciner Wyoming Credit Facility
provides for revolving loans to fund working capital requirements, capital expenditures, to consummate permitted
acquisitions and for all other lawful purposes. The Ciner Wyoming Credit Facility has an accordion feature that allows
Ciner Wyoming to increase the available revolving borrowings under the facility by up to an additional $75,000, subject
to Ciner Wyoming receiving increased commitments from existing lenders or new commitments from new lenders and
the satisfaction of certain other conditions. In addition, the Ciner Wyoming Credit Facility includes a sublimit up to
$20,000 for same-day swing line advances and a sublimit up to $40,000 for letters of credit. Ciner Wyoming’s obligations
under the Ciner Wyoming Credit Facility are unsecured.
The Ciner Wyoming Credit Facility contains various covenants and restrictive provisions that limit (subject to certain
exceptions) Ciner Wyoming’s ability to:
• make distributions on or redeem or repurchase units;
•
incur or guarantee additional debt;
• make certain investments and acquisitions;
•
incur certain liens or permit them to exist;
• enter into certain types of transactions with affiliates of Ciner Wyoming;
• merge or consolidate with another company; and
•
transfer, sell or otherwise dispose of assets.
15
The Ciner Wyoming Credit Facility also requires quarterly maintenance of a consolidated leverage ratio (as defined in the
Ciner Wyoming Credit Facility) of not more than 3.00 to 1.00 and a consolidated interest coverage ratio (as defined in the
Ciner Wyoming Credit Facility) of not less than 3.00 to 1.00.
The Ciner Wyoming Credit Facility contains events of default customary for transactions of this nature, including
(i) failure to make payments required under the Ciner Wyoming Credit Facility, (ii) events of default resulting from
failure to comply with covenants and financial ratios in the Ciner Wyoming Credit Facility, (iii) the occurrence of a
change of control, (iv) the institution of insolvency or similar proceedings against Ciner Wyoming and (v) the occurrence
of a default under any other material indebtedness Ciner Wyoming may have. Upon the occurrence and during the
continuation of an event of default, subject to the terms and conditions of the Ciner Wyoming Credit Facility, the
administrative agent shall, at the request of the Required Lenders (as defined in the Ciner Wyoming Credit Facility), or
may, with the consent of the Required Lenders, terminate all outstanding commitments under the Ciner Wyoming Credit
Facility and may declare any outstanding principal of the Ciner Wyoming Credit Facility debt, together with accrued and
unpaid interest, to be immediately due and payable.
Under the Ciner Wyoming Credit Facility, a change of control is triggered if Ciner Corp and its wholly-owned
subsidiaries, directly or indirectly, cease to own all of the equity interests, or cease to have the ability to elect a majority
of the board of directors (or similar governing body) of our general partner (or any entity that performs the functions of
the Partnership’s general partner). In addition, a change of control would be triggered if the Partnership ceases to own at
least 50.1% of the economic interests in Ciner Wyoming or ceases to have the ability to elect a majority of the members
of Ciner Wyoming’s board of managers.
Loans under the Ciner Wyoming Credit Facility bear interest at Ciner Wyoming’s option at either:
• a Base Rate, which equals the highest of (i) the federal funds rate in effect on such day plus 0.50%, (ii) the
administrative agent’s prime rate in effect on such day or (iii) one-month LIBOR plus 1.0%, in each case, plus
an applicable margin; or
• Eurodollar Rate plus an applicable margin.
The unused portion of the Ciner Wyoming Credit Facility is subject to an unused line fee ranging from 0.225% to 0.300%
per annum based on Ciner Wyoming’s then current consolidated leverage ratio.
At December 31, 2018, Ciner Wyoming was in compliance with all financial covenants of the Ciner Wyoming Credit
Facility.
WE Soda and Ciner Enterprises Facilities Agreement
On August 1, 2018, Ciner Enterprises, the entity that indirectly owns and controls Ciner Wyoming, refinanced its existing
credit agreement and entered into a new facilities agreement, to which WE Soda and Ciner Enterprises (as borrowers),
and KEW Soda, WE Soda, certain related parties and Ciner Enterprises, Ciner Holdings and Ciner Corp (as original
guarantors and together with the borrowers, the “Ciner obligors”), are parties (as amended and restated or otherwise
modified, the “Facilities Agreement”), and certain related finance documents. The Facilities Agreement expires on August
1, 2025.
Even though Ciner Wyoming is not a party or a guarantor under the Facilities Agreement, while any amounts are
outstanding under the Facilities Agreement we will be indirectly affected by certain affirmative and restrictive covenants
that apply to WE Soda and its subsidiaries (which includes us). Besides the customary covenants and restrictions, the
Facilities Agreement includes provisions that, without a waiver or amendment approved by lenders whose commitments
are more than 66-2/3% of the total commitments under the Facilities Agreement to undertake such action, would (i)
prevent transactions with our affiliates that could reasonably be expected to materially and adversely affect the interests
of certain finance parties, (ii) restrict the ability to amend the Company's agreement or Ciner Holdings' company
16
agreement or Company's other constituency documents if such amendment could reasonably be expected to materially
and adversely affect the interests of the lenders to the Facilities Agreement; and (iii) prevent actions that enable certain
restrictions or prohibitions on our ability to upstream cash (including via distributions) to the borrowers under the
Facilities Agreement. In addition, Ciner Enterprises’ ownership in Ciner Holdings, is subject to a lien under the Facilities
Agreement, which enables the lenders under the Facilities Agreement to foreclose on such collateral and take control of
Ciner Holdings if any of WE Soda or KEW Soda or certain of their related parties, or Ciner Enterprises, Ciner Corp or
Ciner Holdings is unable to satisfy its respective obligations under the Facilities Agreement.
9. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities as of December 31, 2018 and 2017 consists of the following:
Reclamation reserve
Derivative instruments and hedges, fair value liabilities
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
2018
2017
$
$
$
$
5,366
5,555
—
10,921
2018
5,080
286
—
5,366
$
$
$
$
5,080
5,301
20
10,401
2017
5,537
300
(757)
5,080
(1) The reclamation adjustments are primarily a result of changes in the self-bond agreement with the Wyoming
Department of Environmental Quality. See Note 12 "Commitments and Contingencies" for additional information.
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 plan covers substantially all
full-time employees hired before May 1, 2001. Ciner Corp’s pension plans had a net unfunded liability balance of $56,883
and $57,370 at December 31, 2018 and December 31, 2017, respectively. Ciner Corp’s 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 $412, $1,358 and $2,015 for the years ended
December 31, 2018, 2017 and 2016, respectively. The decrease in pension costs in 2018 was driven by reduced service
costs from retirements and asset gains from the prior year.
Savings Plan - The 401(k) retirement plan (the “401(k) Plan”) covers all eligible hourly and salaried employees.
Eligibility is limited to all domestic residents and any foreign expatriates who are in the United States indefinitely. The
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, 2018, 2017 and 2016 were $2,833, $3,735 and
$1,625, respectively. The decrease in 2018 was primarily due to the additional profit sharing contributions made during
2017 that did not occur during the current year.
17
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, are not funded, and Ciner Corp has the right to modify or terminate the plan.
The post-retirement plan had a net unfunded liability of $9,851 and $11,465 for the years ended December 31, 2018 and
2017, respectively. The decrease in the obligation as of December 31, 2018 as compared to December 31, 2017 is due to
the Ciner Corp amending its postretirement benefit plan during 2017 to increase eligibility requirements at which
participants may begin receiving benefits, implementing a subsidy rather than a premium for the benefit plan, and
eliminating plan eligibility for individuals hired after December 31, 2016. The result of these changes have resulted in a
postretirement (benefit) cost being amortized to the liability recorded at Ciner Corp during the latter half of 2017 and into
2018. The Company's allocated portion of postretirement (benefit) costs was $(2,940), $(2,823) and $1,400 for the years
ended December 31, 2018, 2017 and 2016, respectively. The postretirement benefit for the Company in 2018 and 2017 is
due to the aforementioned changes made to the postretirement benefit plans during 2017.
18
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss as of December 31, 2018, 2017 and 2016 consists of the following:
BALANCE at December 31, 2015
Interest Rate
Swap
Contract
Natural Gas
Forwards
Contracts
Total
$
(819) $
(3,372) $
(4,191)
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive income (loss)
(401)
781
380
(544)
1,076
532
(945)
1,857
912
BALANCE at December 31, 2016
$
(439) $
(2,840) $
(3,279)
Other comprehensive income (loss) before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive income (loss)
61
376
437
(5,411)
1,044
(5,350)
1,420
(4,367)
(3,930)
BALANCE at December 31, 2017
$
(2) $
(7,207) $
(7,209)
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive income (loss)
(354)
37
(317)
(1,002)
1,037
(1,356)
1,074
35
(282)
BALANCE at December 31, 2018
$
(319) $
(7,172) $
(7,491)
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:
2018
2017
2016
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
12. COMMITMENTS AND CONTINGENCIES
$
$
37
1,037
1,074
$
$
376
1,044
1,420
$
$
781
1,076
1,857
Interest expense
Cost of Products Sold
The Company leases and licenses mineral rights from the U.S. Bureau of Land Management, the state of Wyoming, Rock
Springs Royalty Company, LLC, an affiliate of Anadarko Petroleum, and other private parties. All of these leases and the
license provide for royalties based upon production volume. The remaining leases provide for minimum lease payments
as detailed in the table below. The Company has a perpetual right of first refusal with respect to these leases and license
and intends to continue renewing the leases as has been its practice.
The Company entered into a 10 year rail yard switching and maintenance agreement with a third party, Watco Companies,
LLC (“Watco”), on December 1, 2011. Under the agreement, Watco provides rail-switching services at the Company’s rail
yard. The Company’s rail yard is constructed on land leased by Watco from Rock Springs Grazing Association and on
land by which Watco holds an easement from Anadarko Land Corp; the Rock Springs Grazing Association land lease is
renewable every 5 years for a total period of 30 years, while the Anadarko Land Corp. easement lease is perpetual. The
19
Company has an option agreement with Watco to assign these leases to the Company at any time during the land lease
term. An annual rental of $15 thousand is paid under the easement and an annual rental of $60 thousand is paid under the
lease.
The Company entered into two track lease agreements, collectively, not to exceed 10 years with Union Pacific Company
for certain rail tracks used in connection with the rail yard.
As of December 31, 2018, the total minimum rental commitments under the Company’s various operating leases,
including renewal periods are as follows:
2019
2020
2021
2022
2023
2024 and thereafter
Total
Leased Land
75
$
75
75
75
75
1,275
1,650
$
Track Leases
70
$
70
33
—
—
—
173
$
$
$
Total
145
145
108
75
75
1,275
1,823
Ciner Corp typically enters into operating lease contracts with various lessors for railcars to transport product to customer
locations and warehouses. Railcar leases under these contractual commitments range for periods from 1 to 10 years. Ciner
Corp's obligations related to these railcar leases are $11,131 in 2019, $8,511 in 2020, $5,953 in 2021, $3,805 in 2022,
$1,421 in 2023 and $4,740 in 2024 and thereafter. Total lease expense allocated to the Company from Ciner Corp was
approximately $13,919, $14,628 and $14,476 for the years ended December 31, 2018, 2017 and 2016, respectively, and is
recorded in cost of products sold.
Purchase Commitments - The Company has both physical and financial natural gas supply contracts to mitigate volatility
in the price of natural gas. As of December 31, 2018, these contracts totaled $55,984 for the purchase of a portion of our
gas requirements over approximately the next five years. The aggregate supply purchase agreements for both the physical
and financial contracts have specific commitments of $21,277 in 2019, $15,728 in 2020, $9,974 in 2021, $4,987 in 2022
and $3,874 in 2023. The Company has a separate contract that expires in 2021, for transportation of natural gas with an
average annual cost of approximately $3,823 per year.
Legal and Environmental - From time to time we are party to various claims and legal proceedings related to our business.
Although the outcome of these proceedings cannot be predicted with certainty, management does not currently expect any
of the legal proceedings we are involved in to have a material effect on our business, financial condition and results of
operations. We cannot predict the nature of any future claims or proceedings, nor the ultimate size or outcome of existing
claims and legal proceedings and whether any damages resulting from them will be covered by insurance.
Litigation Settlement- On February 2, 2016, amended on January 3, 2017, Ciner Wyoming filed suit against 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 Anardarko Petroleum Corporation, to mine sodium minerals
from lands located in Sweetwater County, Wyoming (“License”). The License sets the applicable royalty rate based on a
most favored nation clause, where either the royalty rate is set at the same royalty rate we pay to other licensors in
Sweetwater County for sodium minerals, or, if certain conditions are met, the royalty rate is set by the rate paid by a third
party to Anadarko Petroleum Corporation under a separate license. In the lawsuit, we claim that RSRC has, 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.
20
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 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 sale price 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.
Off-Balance Sheet Arrangements - We have a self-bond agreement with the Wyoming Department of Environmental
Quality under which we commit to pay directly for reclamation costs at our Green River, Wyoming plant site. The amount
of the bond was $32,900 as of December 31, 2018 and December 31, 2017, which is the amount we would need to pay
the State of Wyoming for reclamation costs if we cease mining operations currently. The amount of this self-bond is
subject to change upon periodic re-evaluation by the Land Quality Division.
13. AFFILIATES TRANSACTIONS
Ciner Corp is the exclusive sales agent for the Company and through its membership in ANSAC, Ciner Corp is
responsible for promoting and increasing the use and sale of soda ash and other refined or processed sodium products
produced. ANSAC operates on a cooperative service-at-cost basis to its members such that typically any annual profit or
loss is passed through to the members. In the event an ANSAC member exits or the ANSAC cooperative is dissolved, the
exiting members are obligated for their respective portion of the residual net assets or deficit of the cooperative. On
November 9, 2018, Ciner Corp delivered a notice to terminate its membership in ANSAC. The termination from ANSAC
will be effective as of December 31, 2021. As of December 31, 2018, we have not recognized an asset or liability related
to its exit from ANSAC as such an amount is not currently probable or estimable.
All actual sales and marketing costs incurred by Ciner Corp are charged directly to the Company. Selling, general and
administrative expenses also include amounts charged to the Company by Ciner Corp principally consisting of salaries,
benefits, office supplies, professional fees, travel, rent and other costs of certain assets used by the Company. Ciner Corp
has agreed to provide the Company with certain corporate, selling, marketing, and general and administrative services, in
return for which the Company has agreed to pay Ciner Corp an annual management fee and reimburse Ciner Corp for
certain third-party costs incurred in connection with providing such services. These transactions do not necessarily
represent arm's length transactions and may not represent all costs if the Company operated on a standalone basis. In
November 2016, Ciner Corp, on behalf of the Company, entered into a soda ash sales agreement with CIDT, an affiliate of
Ciner Group, that sells soda ash to international markets not served by ANSAC. The terms of our sales agreement with
CIDT are similar to our agreements with other international customers. The receivables associated with these sales are
recorded in accounts receivable - affiliates line item on the balance sheet and interest earned is recorded in the interest
income line item in the Statement of Operations and Comprehensive Income. CIDT is ultimately owned and controlled by
the Ciner Group. There were no sales to CIDT during the twelve months ended December 31, 2018, as the previous
contract concluded in the 2017 year.
21
The total selling, general and administrative costs charged to the Company by affiliates for the years ended December 31,
2018, 2017 and 2016 are as follows:
Ciner Corp
ANSAC (1)
Ciner Resources
Total selling, general and administrative expenses - affiliates
2018
2017
2016
$
$
13,728
2,998
972
17,698
$
$
13,549
2,487
484
16,520
$
$
13,754
3,821
—
17,575
(1) ANSAC allocates its expenses to its members using a pro rata calculation based on sales.
Cost of products sold includes an allocation of Ciner Corp's railcar lease expense (refer to Note 12) and logistics services
charged by ANSAC. These ANSAC logistics costs were $0, $19,573 and $3,278 for the years ended December 31, 2018,
2017 and 2016, respectively. When we elect to use ANSAC to provide freight services for our other non-ANSAC
international sales, ANSAC separately and directly charges the Company for such services. During the year ended 2018
we did not use ANSAC for non-ANSAC international sales. The decrease in freight costs charged by ANSAC was due to
a decrease in non-ANSAC international sales, to CIDT, during the year ended December 31, 2018 compared to 2017.
There were no sales to CIDT during the year ended December 31, 2018, as the previous contract concluded in the 2017
year.
Net sales to affiliates for the years ended December 31, 2018, 2017 and 2016 are as follows:
ANSAC
CIDT
Total
2018
253,345
—
253,345
$
$
$
$
2017
222,231
82,266
304,497
$
$
2016
262,220
9,054
271,274
As of December 31, 2018 and 2017, the Company had due from/to with affiliates as follows:
ANSAC
CIDT
Ciner Corp
Other
Total
2018
2017
Due from
Affiliates
Due to
Affiliates
Due from
Affiliates
Due to
Affiliates
$
$
48,707
7,116
14,324
212
70,359
$
$
743
—
2,014
86
2,843
$
$
57,673
32,841
7,803
195
98,512
$
$
1,338
—
1,641
105
3,084
14. MAJOR CUSTOMERS AND SEGMENT REPORTING
Our operations are similar in 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, 2018,
2017 and 2016 are as follows:
Domestic
International:
ANSAC
CIDT
Other
Total international
Total net sales
2018
$
233,414
$
2017
192,843
$
2016
192,550
253,345
—
—
253,345
486,759
$
222,231
82,266
—
304,497
497,340
$
262,220
9,054
11,363
282,637
475,187
$
22
15. REVENUE
The Company has one reportable segment and our revenue is derived from the sale of soda ash which is our sole and
primary good and service. We account for revenue in accordance with ASC 606, Revenue from Contracts with
Customers, which we adopted on January 1, 2018, using the modified retrospective method.
Performance Obligations. A performance obligation is a promise in a contract to transfer a distinct good or service to the
customer, and is the unit of account in ASC 606. A contract’s transaction price is allocated to each distinct performance
obligation and recognized as revenue when, or as, the performance obligation is satisfied. At contract inception, we assess
the goods and services promised in contracts with customers and identify performance obligations for each promise to
transfer to the customer, a good or service that is distinct. To identify the performance obligations, the Company
considers all goods and services promised in the contract regardless of whether they are explicitly stated or are implied by
customary business practices. From its analysis, the Company determined that the sale of soda ash is currently its only
performance obligation. Many of our customer volume commitments are short-term and our performance obligations for
the sale of soda ash are generally limited to single purchase orders.
When performance obligations are satisfied. Substantially all of our revenue is recognized at a point-in-time
when control of goods transfers to the customer.
Transfer of Goods. The Company uses standard shipping terms across each customer contract with very few
exceptions. Shipments to customers are made with terms stated as Free on Board (“FOB”) Shipping Point.
Control typically transfers when goods are delivered to the carrier for shipment, which is the point at which the
customer has the ability to direct the use of and obtain substantially all remaining benefits from the asset.
Payment Terms. Our payment terms vary by the type and location of our customers. The term between invoicing
and when payment is due is not significant and consistent with typical terms in the industry.
Variable Consideration. We recognize revenue as the amount of consideration that we expect to receive in
exchange for transferring promised goods or services to customers. We do not adjust the transaction price for the
effects of a significant financing component, as the time period between control transfer of goods and services
and expected payment is one year or less. At the time of sale, we estimate provisions for different forms of
variable consideration (discounts, rebates, and pricing adjustments) based on historical experience, current
conditions and contractual obligations, as applicable. The estimated transaction price is typically not subject to
significant reversals. We adjust these estimates when the most likely amount of consideration we expect to
receive changes, although these changes are typically immaterial.
Returns, Refunds and Warranties. In the normal course of business, the Company does not accept returns, nor
does it typically provide customers with the right to a refund.
Freight. In accordance with ASC 606, the Company made a policy election to treat freight and related costs that
occur after control of the related good transfers to the customer as fulfillment activities instead of separate
performance obligations. Therefore freight is recognized at the point in which control of soda ash has transferred
to the customer.
Revenue disaggregation. In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with
customers into geographical regions. The Company determined that disaggregating revenue into these categories
achieved the disclosure objectives to depict how the nature, timing, amount and uncertainty of revenue and cash flows are
affected by economic factors. Refer to Note 14, “Major Customers and Segment Reporting” for revenue disaggregated
into geographical regions.
23
Contract Balances. The timing of revenue recognition, billings and cash collections results in billed receivables, unbilled
receivables (contract assets), and customer advances and deposits (contract liabilities).
Contract Assets. At the point of shipping, the Company has an unconditional right to payment that is only
dependent on the passage of time. In general, customers are billed and a receivable is recorded as goods are
shipped. These billed receivables are reported as “Accounts Receivable, net” on the Balance Sheet as of
December 31, 2018. There were no contract assets as of December 31, 2018 or as of the date of adoption of ASC
606.
Contract Liabilities. There may be situations where customers are required to prepay for freight and insurance
prior to shipment. The Company has elected the practical expedient for its treatment of freight and therefore,
such prepayments are considered a part of the single obligation to provide soda ash. In such instances, a
contract liability for prepaid freight will be recorded. For the twelve months ended December 31, 2018, there
were no customers that required prepaid freight. There were no contract liabilities as of December 31, 2018 or as
of the date of adoption of ASC 606.
Practical and Expedients Exceptions
Incremental costs of obtaining contracts. We generally expense costs related to sales, including sales force salaries and
marketing expenses, when incurred because the amortization period would have been one year or less. These costs are
recorded within sales and marketing expenses.
Unsatisfied performance obligations. We do not disclose the value of unsatisfied performance obligations for contracts
with an original expected length of one year or less.
16. SUBSEQUENT EVENTS
On February 14, 2019, the members of the Board of Managers of Ciner Wyoming, approved a cash distribution to the
members of Ciner Wyoming in the aggregate amount of $20,000. This distribution was payable and paid on February 15,
2019.
******
24
2018 Financial Highlights
Unitholder Information
For the Years Ended December 31
Partnership Headquarters
Website
(in thousands, except per unit)
2018 (1) (2)
2017 (2)
2016 (2)
2015 (2)
2014 (2)
Total revenues and other income
$ 278,512
$ 246,325
$ 279,244
$ 300,635
$ 308,867
Asset impairments
Income (loss) from operations
Net income (loss) from continuing operations
Net income from continuing operations
excluding impairments
Net income (loss) from discontinued operations
Net income (loss)
Per common unit amounts (basic)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Per common unit amounts (diluted)
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
Net income (loss)
Distributions paid per common unit
Average number of common
units outstanding - basic
Average number of common
units outstanding - diluted
Net cash provided by (used in)
Free cash flow (3)
Distributable cash flow (3)
Adjusted EBITDA (3)
Cash and cash equivalents
Total assets
$
18,280
$ 192,538
$ 122,360
$ 140,640
$
17,687
$ 140,047
7.35
1.42
8.77
5.90
0.86
6.76
1.80
12,244
20,234
$
$
$
$
$
$
$
$
$
$ 183,440
$ 383,980
$ 230,241
$ 206,030
2,967
176,559
82,485
85,452
6,182
88,667
4.57
0.50
5.06
3.68
0.28
3.96
1.80
12,232
21,950
112,151
9,807
121,324
121,958
211,483
26,980
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
15,861
181,157
$
378,327
$ (170,699)
90,626
$ (260,443)
106,487
$ $117,884
6,266
$ (311,277)
96,892
$ (571,720)
7.28
0.50
7.78
7.28
0.50
7.78
1.80
12,232
12,232
80,243
65,057
75,970
255,172
(20.80)
(24.94)
(45.75)
(20.80)
(24.94)
(45.75)
2.70
12,232
12,232
144,907
15,805
144,210
157,815
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
26,209
176,108
96,681
122,890
12,149
108,830
8.37
1.05
9.42
8.37
1.05
9.42
14.00
11,326
11,326
189,418
1,566
193,665
195,045
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 235,273
$ 240,553
$ 260,447
39,171
40,244
45,975
$ 1,341,647
$ 1,389,164
$ 1,448,649
$ 1,674,865
$ 2,431,549
Current portion of long-term debt, net
$
115,184
79,740
$
140,037
80,745
80,745
Long-term deb, net
$ 557,574
$ 729,608
$ 990,234
$ 1,130,696
$ 1,190,558
Class A Convertible Preferred Units
Partners’ capital
$ 164,587
$ 423,481
173,431
265,211
—
—
—
151,530
76,336
720,155
(1) On January 1, 2018, NRP adopted Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, and all the related amendments (the “new revenue standard”
and “ASC 606”) to all open contracts using the modified retrospective method. NRP recognized a $70.5 million cumulative effect of adoption adjustment in the opening balance of
partners’ capital on January 1, 2018. Comparative information has not been restated and continues to be reported under the standards in effect for those periods. Refer to “Item 8. Financial
Statements and Supplementary Schedules—Note 2. Summary of Significant Accounting Policies” and “Item 8. Financial Statements and Supplementary Schedules—Note 3. Revenue from
Contracts with Customers” in this Annual Report on Form 10-K for more information.
(2) In December 2018, we sold our construction aggregates materials business and have classified the assets and liabilities, operating results and cash flows of the construction aggre-
gates business as discontinued operations for all periods presented. Refer to “Item 8. Financial Statements and Supplementary Schedules—Note 4. Discontinued Operations” in this Annual
Report on Form 10-K for more information.
(3) See “—Non-GAAP Financial Measures” in this Annual Report on Form 10-K form more information.
Operating activities of continuing operations
$ 178,282
Investing activities of continuing operations
7,607
Financing activities of continuing operations
(6,839)
$ (134,149)
$ (146,373)
$ (166,443)
$ (237,314)
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 1200
Houston, TX 77001-2007
Transfer Agent and Registrar
American Stock Transfer
and Trust Company
Client Operations
6201 15th Avenue
Brooklyn, NY 11219
Website: www.amstock.com
Email: info@amstock.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
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. 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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Natural Resource Partners L.P.
1201 Louisiana Street, 34th Floor
Houston, Texas 77002
www.nrplp.com
2018 Annual Report
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Natural Resource Partners L.P.