Natural Resource Partners L.P.
ANNUAL REPORT
FINANCIAL HIGHLIGHTS
(in thousands, except per unit)
2016
2015
2014
2013
2012
FOR THE YEAR ENDED DECEMBER 31
Total revenues and other income
Asset impairments
Income (loss) from operations
Net income (loss) from continuing operations
Net income from continuing operations
excluding impairments(1)
Net income (loss) from discontinued operations
Net income (loss)
$
$
$
$
$
$
$
PER COMMON UNIT AMOUNTS (BASIC AND DILUTED)
Net income (loss) from continuing operations
$
Net income (loss) from discontinued operations $
Net income (loss)
Distributions paid
Average number of common
units outstanding(2)
NET CASH PROVIDED BY (USED IN)
Operating activities of continuing operations
Investing activities of continuing operations
Financing activities of continuing operations
Distributable cash flow(1)
Adjusted EBITDA(1)
Cash and cash equivalents
Total assets
Total debt at face value
Partners’ capital
$
$
$
$
$
$
$
$
400,059
$ 439,648
16,926
$ 384,545
185,745
95,214
112,140
1,678
96,892
7.65
0.13
7.78
1.80
$
$
$
$
$
$
$
$
$
(170,427)
(260,171)
124,374
(311,549)
(571,720)
(20.78)
(24.97)
(45.75)
2.70
$
$
$
$
$
$
$
$
$
$
$
350,918
$ 352,739
26,209
$
734
176,140
$ 233,740
$
$
$
379,147
2,568
267,165
96,713
$ 169,621
$ 213,355
122,922
$ 170,355
$ 215,923
12,117
$
2,457
–
108,830
$ 172,078
213,355
8.37
1.05
9.42
14.00
$
$
$
$
15.17
0.22
15.39
22.00
$
$
$
19.70
–
19.70
22.00
12,232
12,232
11,326
10,958
$
10,603
100,643
59,943
(161,419)
$
$
$
168,512
6,985
(183,264)
271,415
$
176,617
255,471
$ 262,639
40,371
$
41,204
$
$
$
$
$
$
192,164
$ 246,891
$ 271,408
(169,512)
$ (230,436)
(65,986)
$
(73,574)
$
$
(212,733)
(124,173)
196,929
$ 306,690
$ 296,106
263,871
$ 328,690
$
328,116
48,971
$
92,305
$ 149,424
$ 1,444,681
$ 1,670,035
$ 2,430,819
$ 1,980,354
$ 1,760,381
$ 1,138,932
$ 1,387,073
$ 1,478,056
$ 1,168,039
$ 984,269
$
151,530
$
76,336
$
720,155
$ 616,789
$
617,447
(1) See Non-GAAP Financial Measures on pages 40 and 41 of the Form 10-K for reconciliations.
(2) The unit numbers in the table above give effect to NRP’s one-for-ten (1:10) reverse common unit split that became effective on February 17, 2016.
“We are looking forward to a new era
for NRP in 2017 and beyond.”
To Our Unitholders,
Although 2016 was another extremely challenging year for the energy
industry, the coal markets and industry sentiment began to improve in the
fourth quarter and, as a result of the successful execution of our long-term
deleveraging strategy, NRP entered 2017 as a much stronger company that
is well-positioned for the future. The royalty nature of our coal business,
combined with the steady performance of our diversified platform of
assets in the soda ash and aggregates industries, enabled us to navigate
one of the toughest extended energy markets in decades.
The stock market took notice of our accomplishments, as our unit price nearly tripled
during 2016. Further, our disciplined capital approach led to the recent consummation
of multiple transactions that recapitalized and deleveraged the company and extended
our debt maturities. These transactions mark the beginning of a new era for NRP,
but as we look to the future, we will continue our focus on strengthening our balance
sheet and enhancing our liquidity. We believe that this strategy will create value for
all of our stakeholders.
2016 Accomplishments
In spite of the difficult energy markets, 2016 was marked by a number of successful
accomplishments that set the stage for our recapitalization transactions and have
re-positioned NRP for the future. Among our more noteworthy achievements, we:
» Consummated asset sales generating gross proceeds of $181 million that enhanced
liquidity and accelerated our deleveraging;
» Reduced our debt by $248 million;
» Sustained our quarterly distribution to unitholders at $0.45 per unit;
» Continued our focus on reducing costs across all of our business segments;
» Through our governance and ownership of our soda ash business, assured
$46.6 million of cash distributions; and
» Recorded the second best year in terms of reportable injuries in VantaCore’s history.
As a result of our efforts, both our unit and bond prices improved dramatically over the
course of the year, and we created the opportunity to structure a longer-term solution.
“Between January 1, 2016
and April 3, 2017, we
have reduced debt by
$484 million and extended
the maturities of both our
bonds and credit facility.”
N AT U R A L R E S O U R C E PA R T N E R S L . P. 2 0 16 A N N UA L R E P O R T
1
“The last two years have
been challenging for
everyone in the coal
and energy markets,
but NRP has emerged
from these difficult times
as a stronger company
that is well-positioned
to take advantage
of opportunities and
create value for
our stakeholders.”
Summary of Recapitalization Transactions
In March 2017, we completed a series of transactions in order to strengthen our
balance sheet, enhance our liquidity and reposition the partnership for long-term
growth, including:
» The issuance of $250 million of a new class of 12.0% preferred units, together with
warrants to purchase common units, to certain entities controlled by funds affiliated
with The Blackstone Group, L.P. and affiliates of GoldenTree Asset Management LP;
» The exchange of $241 million of our 9.125% Senior Notes due 2018
(the “2018 Notes”) for $241 million of a new series of 10.500% Senior Notes
due 2022 (the “2022 Notes”), and the sale of $105 million of additional
2022 Notes in exchange for cash proceeds; and
» The extension of Opco’s revolving credit facility to April 2020, with commitments
thereunder reduced to $180 million.
We used the proceeds from these transactions to pay off the full $210 million balance
on Opco’s revolving credit facility and redeem $90 million of the remaining 2018 Notes.
Additionally, we paid $41 million in principal on the Opco Notes in the first quarter
of 2017. After accounting for the issuance of $105 million of additional 2022 notes
described above, we have reduced our debt by an additional $236 million since the
end of 2016.
Looking Ahead – A New Era
Our recent transactions provided us with substantial liquidity, improved our balance
sheet and also brought in a new strategic partner in Blackstone. Between January 1, 2016
and April 3, 2017, we have reduced debt by $484 million and extended the maturities
of both our bonds and credit facility. As we look ahead, we will continue to focus on
our balance sheet, but will also be exploring new opportunities to grow. The recent
improvements in the markets for both metallurgical and thermal coal, combined with
the balance and diversification of our soda ash and aggregates businesses, position
NRP well for the future.
The last two years have been challenging for everyone in the coal and energy markets,
but NRP has emerged from these difficult times as a stronger company that is well-
positioned to take advantage of opportunities and create value for our stakeholders.
We are looking forward to a new era for NRP in 2017 and beyond.
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
2
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2016 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 partnership 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 or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange
Act.
Large Accelerated Filer
Accelerated Filer
Non-accelerated Filer
Smaller Reporting Company
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, 2016, was $119.7 million based on
a closing price on that date of $14.35 per unit as reported on the New York Stock Exchange.
As of February 24, 2017, there were 12,232,006 common units outstanding.
Documents incorporated by reference: None.
TABLE OF CONTENTS
PART I
Items 1. and 2. Business and Properties
Item 1A.
Risk Factors
Item 1B.
Item 3.
Item 4.
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
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
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors and Executive Officers of the Managing General Partner and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Item 15.
Signatures
Exhibits, Financial Statement Schedules
PART IV
1
23
36
36
37
38
39
42
68
70
114
114
115
116
123
134
135
141
145
150
i
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
Statements included in this Annual Report on Form 10-K may constitute forward-looking statements. All statements, other
than statements of historical facts, included herein or incorporated herein by reference are "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 ability to service our debt and make distributions to our limited partners;
our financial strategy;
prices of and demand for coal, trona and soda ash, construction aggregates, frac sand and other natural resources;
estimated revenues, expenses and results of operations;
the amount, nature and timing of capital expenditures;
projected production levels by our lessees and VantaCore Partners LLC ("VantaCore");
• Ciner Wyoming LLC’s ("Ciner Wyoming") trona mining and soda ash refinery operations;
•
the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and
of scheduled or potential regulatory or legal changes; and
•
global and U.S. economic conditions.
These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations,
estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties.
We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed
or implied in the forward-looking statements.
You should not put undue reliance on any forward-looking statements. See "Item 1A. Risk Factors" in 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. References to NRP
Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation ("NRP Finance") is a
wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Partnership Structure and Management
We are a publicly traded Delaware limited partnership formed in 2002. We own, operate, manage and lease a diversified
portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates and
other natural resources. Our business is organized into three operating segments:
Coal Royalty and Other—consists primarily of coal royalty and coal related transportation and processing assets. Other
assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. Our coal reserves are primarily located
in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of
states across the United States. Our oil and gas royalty assets are 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. We receive regular quarterly distributions
from this business.
VantaCore—consists of our construction materials business that operates hard rock quarries, an underground limestone
mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee,
Kentucky and Louisiana.
Our Corporate and Financing segment includes functional corporate departments that do not earn revenues. Costs incurred
by these departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other
corporate-level activity not specifically allocated to a segment.
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 Investor Rights Agreement with Adena Minerals, LLC ("Adena Minerals") and 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 is entitled to nominate eleven directors to the Board of Directors of GP Natural Resource Partners
LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals,
and one director to Blackstone.
The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited
Partnership and Quintana Minerals Corporation, companies controlled by Mr. Robertson, and they 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
2017 Recapitalization Transactions
On March 2, 2017, we completed a series of transactions in order to strengthen our balance sheet, enhance our liquidity
and ultimately reposition the partnership for long-term growth, including:
•
•
the issuance of $250 million of a new class of 12.0% preferred units representing limited partner interests in NRP,
together with warrants to purchase common units, to Blackstone and GoldenTree;
the exchange of $241 million of our 9.125% Senior Notes due 2018 (the "2018 Notes") for $241 million of a new
series of 10.500% Senior Notes due 2022 (the "2022 Notes"), and the sale of $105 million of additional 2022 Notes
in exchange for cash proceeds; and
•
the extension of Opco’s revolving credit facility to April 2020, with commitments thereunder reduced to $180 million.
We used a portion of the proceeds from these transactions to repay Opco’s revolving credit facility in full and pay all fees
and expenses associated with the transactions described above. We will also use a portion of the proceeds to redeem the remaining
2018 Notes. On March 3, 2017, we delivered a notice of partial redemption for $90.0 million of our outstanding 2018 Notes at a
redemption price of 104.563%, plus accrued and unpaid interest to the redemption date. This partial redemption of the 2018 Notes
is expected to occur on April 3, 2017. We will redeem all of the remaining 2018 Notes within 60 days after October 1, 2017 at
the then-applicable price and pay all accrued and unpaid interest thereon. For more information on these transactions, including
the terms of the preferred units, warrants and 2022 Notes, see "Management’s Discussion and Analysis of Financial Condition
and Results of Operations—Liquidity and Capital Resources—2017 Recapitalization Transactions."
2016 Asset Sales
Prior to completion of the recapitalization transactions discussed above, we had been pursuing or considering a number of
actions, including dispositions of assets, in order to mitigate the effects of adverse market developments and scheduled debt
principal payments. As part of this plan, we sold assets during the year ended December 31, 2016, for total gross proceeds of
$181.0 million that consisted of the following:
1) Oil and gas working interest in the Williston Basin for $116.1 million gross sales proceeds. Our exit from the non-operated
oil and gas working interest business represented a strategic shift to reduce debt and focus on our coal royalty, soda ash and
construction aggregates business segments.
2) Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for
$36.4 million gross sales proceeds.
3) Aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee for
$10.0 million gross sales proceeds.
4) Mineral reserves in multiple sale transactions for cumulative $17.3 million of gross sales proceeds. These amounts
primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas royalty interests.
Additional asset sales during the year included sales of land and plant and equipment for $1.2 million of gross proceeds.
Segment and Geographic Information
The amount of total revenue for each of our operating segments in the last three years is shown below (dollars in thousands).
For additional operating segment information, please see "Note 4. Segment Information" in the Notes to Consolidated Financial
Statements under Item 8 in this Annual Report on Form 10-K and "Management's Discussion and Analysis of Financial Condition
and Results of Operations—Results of Operations" under Item 7 in this Annual Report on Form 10-K, which are both incorporated
herein by reference.
2
2016
Revenues
Percentage of total
2015
Revenues
Percentage of total
2014
Revenues
Percentage of total
Coal Royalty and Other Segment
Coal Royalty and
Other
Soda Ash
VantaCore
Total
$
$
$
239,183
$
40,061
$
120,815
$
400,059
60%
10%
30%
250,717
$
49,918
$
139,013
$
439,648
57%
11%
32%
267,451
$
41,416
$
42,051
$
350,918
76%
12%
12%
We do not operate any coal mines, but lease our reserves to experienced mine operators under long-term leases that grant
the operators the right to mine and sell our reserves in exchange for royalty payments. A typical lease has a five- to ten-year base
term, with the lessee having an option to extend the lease for additional terms. Leases may include the right to renegotiate rents
and royalties for the extended term. We also own and manage coal related infrastructure assets that generate additional revenues
in the Illinois Basin. In addition, we own aggregates and industrial mineral reserves located in a number of states across the country.
We derive a small percentage of our aggregates and industrial mineral revenues by leasing our owned reserves to third party
operators who mine and sell the reserves in exchange for royalty payments.
Under our standard lease, 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 pre-established minimum quarterly or annual payments.
These minimum rentals reflect amounts we are entitled to receive even if no mining activity occurred during the period. Minimum
rentals are usually credited against future royalties that are earned as minerals are produced.
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 legacy costs, black lung benefits and workers’ compensation costs associated with
operating the mines on our coal and aggregates properties. We typically pay property taxes on our properties, which are largely
reimbursed by our lessees pursuant to the terms of the various lease agreements.
3
Coal Production and Reserves Information
The following table presents coal production for the year ended December 31, 2016 and coal reserves information as of
December 31, 2016 for the properties that we owned by major coal region:
Appalachia:
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total
Production
Underground
Surface
Total
Proven and Probable Reserves (1)
(Tons in thousands)
2,312
13,222
2,776
18,310
8,116
3,781
0.4
30,207
297,896
749,328
73,148
1,120,372
302,626
—
—
1,422,998
—
240,293
17,018
257,311
5,307
34,738
1,957
299,313
297,896
989,621
90,166
1,377,683
307,933
34,738
1,957
1,722,311
(1) In excess of 95% of the reserves presented in this table are currently leased to third parties.
The following table presents the sulfur content, the typical quality of our coal reserves and the type of coal by major coal
region as of December 31, 2016:
Sulfur Content
Typical Quality (1)
Type of Coal
Compliance
Coal (2)
Low
(<1.0%)
Medium
(1.0%
to
1.5%)
High
(>1.5%)
Total
Heat
Content
(Btu per
pound)
Sulfur
(%)
(Tons in thousands)
32,807
490,556
60,284
583,647
—
32,807
688,924
69,973
791,704
—
— 34,738
82
1,957
828,399
583,729
905
254,223
16,617
271,745
2,155
—
—
273,900
264,184
46,473
3,577
314,234
305,778
—
—
620,012
297,896
989,620
90,167
1,377,683
307,933
34,738
1,957
1,722,311
12,854
13,258
13,380
13,178
11,472
8,800
6,964
2.76
0.90
0.83
1.30
3.29
0.65
0.69
Steam
Met (3)
(Tons in thousands)
265,089
567,359
66,893
899,341
307,933
34,738
1,875
1,243,887
32,807
422,262
23,273
478,342
—
—
82
478,424
Appalachia
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder
River Basin
Gulf Coast
Total
(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 for Illinois (typically 12%
moisture) and Northern Powder River Basin (typically 25%).
(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.
(3) For purposes of this table, we have defined metallurgical coal reserves as reserves located in those 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 steam coal. In 2016, approximately 37% of our coal royalty revenues and
approximately 35% of the related production from metallurgical coal. In prior years metallurgical coal royalty revenues
accounted for a greater portion of total revenue when compared to the proportion of total production. In 2016, pricing for
metallurgical coal was comparable to thermal coal pricing.
4
Methodologies Used in Mineral Reserve Estimation
All of the reserves reported above are recoverable proved or probable reserves as determined by the SEC’s Industry Guide
7 and are estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers
in the estimation of our proved 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."
Major Coal Producing Properties
The following is a summary of our major coal producing properties in each region:
Appalachia—Northern Appalachia
Hibbs Run. The Hibbs Run property is located in Marion County, West Virginia. In 2016, approximately 1.5 million tons
were produced from this property. We lease this property to Ohio Valley Resources, Inc., a subsidiary of Murray Energy Corporation.
Coal from this property is produced from longwall mines. The royalty rate for this property is a low fixed rate per ton and has a
significant effect on the per ton revenue for the region. The coal from this property is shipped by rail to utility customers.
Area F. Area F is located in Randolph and Upshur Counties, West Virginia. In 2016, approximately 0.4 million tons were
produced from this property. We lease this property to Carter Roag Coal Company, a subsidiary of United Coal Company, LLC
(owned by Metinvest). Production comes from the Pleasant Hill Sewell Seam deep mine and 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 the Ukraine.
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The map below shows the location of our major properties in Northern Appalachia:
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Appalachia—Central Appalachia
Contura-CAP. The Contura-CAP property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In
2016, approximately 3.2 million tons were produced from this property. We lease this property to subsidiaries of Contura Energy,
Inc. Production comes from both underground and surface mines and is trucked to one of two preparation plants. Coal is shipped
via both the CSX and Norfolk Southern railroads to utility and metallurgical customers.
Dingess-Rum. The Dingess-Rum property is located in Logan, Clay and Nicholas Counties, West Virginia. This property
is leased to subsidiaries of Alpha Natural Resources, Inc. and Blackhawk Mining, LLC. In 2016, approximately 2.1 million tons
were produced from the property. Both steam and metallurgical coal are produced from underground and surface mines and is
transported by belt or truck to preparation plants on the property. Coal is shipped via the CSX railroad to utility customers and to
various export metallurgical customers.
Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2016, approximately 1.7 million tons
were produced from this property. This property is leased to a subsidiary of Revelation Energy, LLC. Production comes from both
underground and surface mines. This property has the ability to ship coal on both the CSX and Norfolk Southern railroads.
Pinnacle. The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. In 2016, approximately
1.3 million tons of metallurgical coal were produced from our reserves on this property. We also own an overriding royalty interest
on coal produced from the reserves that we do not own at this property, from which we derive additional revenues. We lease the
property to a subsidiary of Seneca Resources, LLC. Production comes from a longwall mine and is transported by beltline to a
preparation plant and is then shipped via railroad and barge to both domestic and export customers.
Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. In 2016, approximately 1.3 million
tons were produced from this property. We lease the property to a subsidiary of Arch Coal, Inc. Production comes from underground
mines and is transported primarily by beltline to a preparation plant on adjacent property and shipped on the Norfolk Southern or
CSX railroads to utilities and pulverized coal injection customers.
Kingston. The Kingston property is located in Fayette and Raleigh Counties, West Virginia. In 2016, approximately 0.7
million tons were produced from the property. We lease this property to a subsidiary of Alpha Natural Resources, Inc. Both steam
and metallurgical coal are produced from underground and surface mines that is transported by belt or truck to a preparation plant
on the property or shipped raw. Coal is shipped via both the CSX railroad and by truck to barges to steam customers and various
export metallurgical customers.
Kepler/National Mines Corp. The Kepler/National Mines Corp. property is located in Wyoming County, West Virginia. In
2016, approximately 0.7 million tons were produced from the property. We lease this property to a subsidiary of Alpha Natural
Resources, Inc. Metallurgical coal is produced from two underground 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.
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The map below shows the location of our major properties in Central Appalachia:
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Appalachia—Southern Appalachia
Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2016, approximately 1.5 million tons
were produced from this property. We lease the property to a subsidiary of Seneca Coal Resources, LLC. Production comes from
an underground longwall mine and is transported primarily by beltline to a preparation plant. Metallurgical products are then
shipped via railroad and barge to both domestic and export customers.
BLC Properties. The BLC properties are located in Kentucky and Tennessee. In 2016, approximately 1.3 million tons were
produced from these properties. We lease these properties to a number of operators including Middlesboro Mining Properties, Inc.,
Revelation Energy, LLC and Corsa Coal Corp. Production comes from both underground and surface mines and is trucked to
preparation plants and loading facilities operated by our lessees. Coal is transported by truck and is shipped via both CSX and
Norfolk Southern railroads to utility and industrial customers.
The map below shows the location of our major properties in Southern Appalachia:
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Illinois Basin
Williamson. The Williamson property is located in Franklin and Williamson Counties, Illinois. The property is under lease
to a subsidiary of Foresight Energy LP, and in 2016, approximately 5.0 million tons were mined on the property. This production
is from a longwall mine and is shipped primarily via the Canadian National railroad to domestic utility customers and to various
export customers.
Macoupin. The Macoupin property is located in Macoupin County, Illinois. The property is under lease to a subsidiary of
Foresight Energy LP, and in 2016, approximately 2.1 million tons were shipped from the property. Production is from an underground
mine and is shipped via the Norfolk Southern or Union Pacific railroads or by barge to utility customers such or loaded into barges
for shipment to export customers.
Hillsboro/Deer Run. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. The property is under
lease to a subsidiary of Foresight Energy, and in 2016, approximately 0.1 million tons were shipped from the property. When
active, production at the Deer Run mine on our Hillsboro property is from an underground longwall mine and is shipped via either
the Union Pacific, Norfolk Southern or Canadian National railroads or by barges to domestic utilities or export customers. The
Deer Run mine has been idled since March 2015 as a result of elevated carbon monoxide levels in the mine. In July 2015, we
received a notice from Foresight Energy declaring a force majeure event at the mine as a result of the elevated carbon monoxide
levels. We believe Foresight's claim of force majeure has no merit, and we are vigorously pursuing our claims against them through
a lawsuit that we filed in November 2015. However, the effect of a valid force majeure declaration would relieve Foresight Energy
of its obligation to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. For more information
on the idling of the Deer Run mine, see "Item 3. Legal Proceedings" included elsewhere in this Annual Report on Form 10-K.
In addition to these properties, we own loadout and other transportation assets at the Williamson and Macoupin mines and
at the Sugar Camp mine, which is another mine operated by Foresight Energy. See "—Coal Transportation and Processing Assets."
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The map below shows the location of our major properties in the Illinois Basin:
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Northern Powder River Basin
Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2016,
approximately 3.8 million tons were produced from our property by a subsidiary of Westmoreland Coal Company. Coal is produced
by surface dragline mining, and the coal is transported by either truck or beltline to the four-unit 2,200-megawatt Colstrip generation
station located at the mine mouth.
The map below shows the location of our property in the Northern Powder River Basin:
Coal Transportation and Processing Assets
We own transportation and processing infrastructure related to certain of our coal properties. We own loadout and other
transportation assets at the Williamson and Macoupin mines in the Illinois Basin. 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 LP. While we
own coal reserves at the Williamson and Macoupin mines, we do not own coal reserves at the Sugar Camp mine. We typically
lease this infrastructure to third parties and collect throughput fees; however, at the loadout facility at the Williamson mine, we
operate the coal handling and transportation infrastructure and have subcontracted out that responsibility to a third party.
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Other Assets
As of December 31, 2016, we owned an estimated 250 million tons of aggregates reserves primarily located in Kentucky,
Washington and Indiana. We lease a portion of these reserves to third parties in exchange for royalty payments. We also lease
approximately 90 million tons of these reserves to VantaCore's Grand Rivers operation. The structure of these leases is similar to
our coal leases, and these leases typically also require minimum rental payments in addition to royalties. During 2016, our aggregates
lessees produced 1.5 million tons of aggregates from these properties and we received $3.2 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:
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•
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•
•
approximately 300,000 gross acres of oil and gas mineral rights in Louisiana, of which over 53,000 acres
were leased as of December 31, 2016;
approximately 95,000 net mineral acres of coal rights (primarily lignite and some bituminous coal) in the
Gulf Coast region, of which approximately 4,800 acres are leased in Louisiana, Alabama and Texas;
an overriding royalty interest of 1% 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 remain largely undeveloped, BRP has an ongoing program to identify additional
opportunities to lease its minerals to operating parties.
Soda Ash Segment
We own a 49% non-controlling equity interest in Ciner Wyoming, which 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 six large continuous mining machines and ten 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. The following map provides an aerial overview of Ciner Wyoming’s surface operations:
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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 over 50 years.
Deca Rehydration. The evaporation stage of trona ore processing produces a precipitate and natural by-product called deca.
"Deca," short for sodium carbonate decahydrate, is one part soda ash and ten parts water. Solar evaporation causes deca to crystallize
and precipitate to the bottom of the four main surface ponds at the Green River Basin facility. Ciner Wyoming’s 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
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from the soda ash. The separated deca crystals are then blended with partially processed trona ore in the dissolving stage. This
process enables Ciner Wyoming to reduce waste storage needs and convert what is typically a waste product into a usable raw
material. As a result of this process, Ciner Wyoming has been able to reduce the amount of short tons of trona ore it takes to produce
one short ton of soda ash.
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, 2016, Ciner Wyoming shipped approximately 96% of its soda ash to customers initially via rail under
a contract with Union Pacific that expires on December 31, 2017, and the plant receives rail service exclusively from Union Pacific.
Ciner Wyoming 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") 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 largest customer is ANSAC, which buys soda ash (through Ciner Wyoming’s sales agent) and
other of its member companies for further export to its customers. ANSAC accounted for approximately 55% of Ciner Wyoming’s
net sales in 2016. 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.
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. Under the license with Rock Springs, the applicable royalty rate may vary based on a most favored
nation clause in the license which is currently the subject of litigation in Wyoming.
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.
VantaCore Segment
VantaCore is a construction materials company that we acquired on October 1, 2014. VantaCore operates four limestone
quarries, one underground limestone mine, five sand and gravel plants, two asphalt plants and two marine terminals. VantaCore
is headquartered in Philadelphia, Pennsylvania, and its operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky
and Louisiana. As of December 31, 2016, VantaCore controlled approximately 400 million tons of estimated aggregates reserves,
including approximately 117 million tons of reserves leased at the Grand Rivers operation from the Coal Royalty and Other
segment. The reserve estimates for each of VantaCore’s properties were prepared internally and audited by an independent third
party advisor. For the year ended December 31, 2016, VantaCore sold approximately 5.5 million tons of crushed stone and gravel,
including brokered stone, 1.2 million tons of sand and 0.2 million tons of asphalt. VantaCore’s four operating businesses are Laurel
Aggregates, located in Lake Lynn, Pennsylvania, Winn Materials/McIntosh Construction, located in Clarksville, Tennessee, Grand
Rivers, located in Grand Rivers, Kentucky and Southern Aggregates, located near Baton Rouge, Louisiana. VantaCore’s business
is seasonal, with production typically lower in the first quarter of each year due to winter weather. The following map shows the
locations of each of VantaCore’s operations.
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Laurel Aggregates
Laurel Aggregates is a limestone mining company located in Lake Lynn, Pennsylvania. Its operations consist of a surface
and underground mines and use conventional drilling, blasting and crushing methods. The surface mine is located on approximately
100 acres of owned property, and the underground reserves are located on approximately 670 acres of leased property. Laurel pays
royalties for material mined and sold from its leased property. Laurel also brokers stone for third party quarries located in Ohio
and Pennsylvania. Crushed stone is loaded into third party trucks for delivery to customers located in southwestern Pennsylvania,
northeastern West Virginia and eastern Ohio. Laurel’s customers consist of oilfield service companies, natural gas exploration and
production companies and construction and contracting companies.
Winn Materials/McIntosh Construction
Winn Materials’ operations consist of two crushed stone quarries and a river terminal, while McIntosh is a complementary
asphalt producer and paving company. Together, the two companies function as a vertically integrated unit. The operations of
Winn/McIntosh are located in Clarksville, Tennessee, which is located approximately 45 miles northwest of Nashville and is
Tennessee’s fifth largest city.
Winn mines and produces hard rock limestone using conventional drilling, blasting and crushing methods. Winn primarily
leases its properties at its two quarries located in Clarksville and in Trenton, Kentucky and pays royalties for material produced
and sold from the leased properties. Winn’s marine terminal business is located on the Cumberland River, adjacent to Winn’s
Clarksville quarry. Its dock transloads various materials by barge. Through the river terminal, Winn loads out crushed stone and
also imports products such as river and granite sand, fertilizer and agricultural products for the local and regional markets. The
river terminal is currently being expanded to meet growing demand for additional imported product into these markets. Crushed
stone produced at Winn’s quarries and products imported from the river terminal are loaded onto third party trucks for delivery to
Winn’s customers.
McIntosh sells asphalt to third parties and also operates its own paving business. Winn supplies most of McIntosh’s crushed
stone and sand used for both its asphalt production and construction needs. The Winn/McIntosh businesses sell to and provide
services for residential, commercial and industrial customers. These businesses also supply and provide construction services for
infrastructure and highway construction projects primarily within Montgomery County, Tennessee, including for Fort Campbell,
one of the largest Army bases in the United States.
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Grand Rivers
VantaCore purchased this 514 acre hard rock quarry operation located on the Tennessee River near Grand Rivers, Kentucky
from one of NRP’s aggregates lessees that had previously idled the operation. Under VantaCore’s ownership, this operation continues
to lease reserves from NRP and sell its limestone aggregates in both the local market loaded onto third party trucks and to river-
based markets through a barge load out terminal.
The Grand Rivers quarry produces various grades of crushed limestone products mined through its open pit using conventional
drilling, blasting and crushing methods performed by a third party mining contractor. Grand Rivers pays royalties for material
produced and sold from the leased property to a subsidiary of NRP. Crushed stone is loaded into third party trucks to customers
in Kentucky and barges for delivery to customers along the Mississippi River Basin and related waterways. Grand Rivers customers
currently consist primarily of ready mix concrete companies and construction and contracting companies.
Southern Aggregates
Southern Aggregates is a sand and gravel mining company based in Denham Springs, Louisiana approximately 25 miles
northeast of Baton Rouge, Louisiana. Southern operates five sand and gravel operations. Suction dredges extract sand and gravel,
and the mined material is processed at plants generally located at each site. The plants separate gravel and saleable sand from
waste sand and clays, with the waste returned to mined-out sections of pits. The saleable sand and gravel material is loaded onto
third party trucks for delivery to Southern’s customers. Southern leases its mineral reserves and pays royalties for material produced
and sold from the leased properties. Southern’s markets extend approximately 100 miles west and south from its operating locations,
including to the cities of Baton Rouge, Lafayette and New Orleans. Southern’s customers consist primarily of ready mix concrete
companies, asphalt producers and contractors.
Significant Customers
We have a significant concentration of revenues with Foresight Energy and its subsidiaries, with total revenues of $63.4
million in 2016. The exposure is spread out over four different mining operations. We are currently in disputes with and have filed
two separate lawsuits against two of Foresight Energy's subsidiaries, Hillsboro Energy for breach of contract due to wrongful
declaration of force majeure at the Deer Run mine, and Macoupin Energy for breach of contract for wrongful recoupment of
previously paid minimum royalties. For additional information on the Deer Run mine lawsuit, see Note 15. "Major Customers"
in the Notes to Consolidated Financial Statements under "Item 8. Financial Statements and Supplementary Data" and "Item 3.
Legal Proceedings" included elsewhere in this Annual Report on Form 10-K.
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 and hydroelectric power.
The construction aggregates industry that VantaCore operates in is highly competitive and fragmented with a large number
of independent local producers operating in VantaCore’s local markets. Additionally, VantaCore also competes against large private
and public companies, some of which are significantly vertically integrated. Therefore, there is intense competition in a number
of markets in which VantaCore operates. This significant competition could lead to lower prices and lower sales volumes in some
markets, negatively affecting our earnings and cash flows.
Our trona mining and soda ash refinery business in the Green River Basin, Wyoming, 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
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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 a significant percentage of our coal and aggregates reserves in fee as of December 31, 2016. We lease the remainder
from unaffiliated third parties, including leasing aggregates reserves for VantaCore’s construction materials business. Ciner
Wyoming also leases or licenses its trona reserves. We believe that we have satisfactory title to all of our mineral properties, but
we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in
certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real
property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will
materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the
operation of our business.
For most of our properties, the surface, oil and gas and mineral or coal estates are not owned by the same entities. Some of
those entities are our affiliates. State law and regulations in most of the states where we do business require the oil and gas owner
to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the
existence of the severed estates will materially impede development of the minerals on our properties.
Regulation and Environmental Matters
General
Operations on our properties must be conducted in compliance with all applicable federal, state and local laws and regulations.
These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety,
mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed,
management of materials generated by mining operations, surface subsidence from underground mining, water pollution,
legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife
protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable
laws and management of electrical equipment containing polychlorinated biphenyls (PCBs). Because of extensive, comprehensive
and often ambiguous regulatory requirements, violations during natural resource extraction operations are not unusual and,
notwithstanding compliance efforts, we do not believe violations can be eliminated entirely.
While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations,
those costs have been and are expected to continue to be significant. Our lessees in our coal and aggregates royalty businesses are
required to post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation
and mine closures, including the cost of treating mine water discharge when necessary. In many states our lessees also pay taxes
into reclamation funds that states use to achieve reclamation where site specific performance bonds are inadequate to do so.
Determinations by federal or state agencies that site specific bonds or state reclamation funds are inadequate could result in increased
bonding costs for our lessees or even a cessation of operations if adequate levels of bonding cannot be maintained. We do not
accrue for reclamation costs because our lessees are both contractually liable and liable under the permits they hold for all costs
relating to their mining operations, including the costs of reclamation and mine closures. Although the lessees typically accrue
adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals
to be insufficient. In recent years, compliance with these laws and regulations has substantially increased the cost of coal mining
for all domestic coal producers.
In addition, the electric utility industry, which is the most significant end-user of steam 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.
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Many of the statutes discussed below also apply to VantaCore’s construction aggregates mining and production operations
and 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.
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 has begun 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 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. The rule will 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. This rule is expected to have a material adverse effect on the demand for coal by electric power generators and 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 Clean Power Plan Rule pending a decision by the
District of Columbia Circuit as well as any subsequent review by the Supreme Court.
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. Oral arguments are currently scheduled
for April 2017.
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. Prior to taking office, President
Trump expressed his desire that the United States withdraw from the Paris Climate Agreement.
EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the
United States, including coal-fired electric power plants, on an annual basis.
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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 our
VantaCore construction aggregates and Ciner Wyoming soda ash businesses.
Water Discharges
Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water Act and analogous
state laws and regulations create two permitting programs for mining operations. The National Pollutant Discharge Elimination
System (NPDES) program under Section 402 of the statute is administered by the states or EPA and regulates the concentrations
of pollutants in discharges of waste and storm water from a mine site. The Section 404 program is administered by the Army Corps
of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise "waters
of the United States." The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and
may include land features not commonly understood to be a stream or wetlands. 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 has been challenged by a
number of states and private parties and was stayed on a nationwide basis by the Sixth Circuit Court of Appeals in October 2015.
In February 2016, the United States Court of Appeals for the Sixth Circuit ruled that it has exclusive jurisdiction over the challenge.
In January 2017, the Supreme Court decided to hear a petition by industry groups challenging the Sixth Circuit’s jurisdictional
determination. 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 EPA’s review of permits, it has 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.
NRP has been named as a defendant in one of these lawsuits. 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. While it is too early to determine the merits or
predict the outcome of any of these lawsuits, 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 lessees, VantaCore 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. Regulatory authorities or individual citizens who bring
civil actions under SMCRA may attempt to assign the liabilities of our coal lessees to us if any of these lessees are not financially
capable of fulfilling those obligations.
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.
Regulations under SMCRA include a "stream buffer zone" rule that prohibits certain mining activities near streams. In 2008,
the federal Office of Surface Mining (OSM), which implements SMCRA, revised the stream buffer zone rule, making it more
clear that valley fills are not prohibited by the rule. Environmental groups challenged the revision to the buffer zone rule in federal
court. In February 2014, the federal court vacated the 2008 rule and in December 2014, OSM reinstated the previous version of
the rule, without clarifying whether the previous version of the rule impacts the ability to construct excess fills. In December 2016,
OSM finalized the "Stream Protection Rule," a re-written version of the stream buffer zone rule which requires coal operators to
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restrict mining within 100 feet of waterways. The rule also requires states to impose additional information gathering and monitoring
at and around coal mining sites and mandates new financial assurance and reclamation requirements. The rule was repealed by
Congress in February 2017; however, to the extent the rule is ever reinstated, it could restrict our lessees’ ability to develop new
mines, or could require our lessees to modify existing operations, which could have an adverse effect on our coal-related revenues.
Employees and Labor Relations
As of January 31, 2017, affiliates of our general partner employed 63 people who directly supported our operations. None
of these employees were subject to a collective bargaining agreement. We employed 221 people who supported VantaCore’s
construction aggregates mining and production operations. None of these employees were subject to a collective bargaining
agreement.
Website Access to Company 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. Also included on our website are
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. 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.
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ITEM 1A.
RISK FACTORS
Risks Related to Our Business
To the extent our board of directors deems appropriate, it may determine to decrease the amount of our quarterly distribution
or suspend or eliminate the distribution altogether. In addition, our debt agreements and our partnership agreement place
restrictions on our ability to pay 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. 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. 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. Following the recapitalization transactions, we still 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, you may be required to pay taxes in excess of any future distributions we make. Your share of our portfolio
income may be taxable to you even though you receive other losses from our activities. See "—Tax Risks to Common Unitholders
—You are required to pay taxes on your share of our income even if you do not receive any cash distributions from us."
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. 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 "Management’s Discussion and Analysis of Financial Condition and Results
of Operations—Liquidity and Capital Resources—2017 Recapitalization Transactions" and "Item 8. Financial Statements and
Supplementary Data—Note 11. Debt and Debt—Affiliate."
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business
prospects.
As of December 31, 2016, we and our subsidiaries had approximately $1.1 billion of total indebtedness. Following the
execution of our recapitalization transactions, we and our subsidiaries had approximately $944 million of total indebtedness. The
terms and conditions governing our indebtedness, including the indentures for NRP’s 2018 Notes and 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. We are required to make substantial principal repayments each year in connection with Opco’s senior
notes, with approximately $81 million due thereunder each year through 2018. While we intend to make these payments using
cash from operations, 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.
Foresight Energy is our largest lessee, and ongoing disputes with them could have an adverse effect on our financial condition
and results of operations. In addition, if the Deer Run mine remains idled for an extended period or does not resume operations,
our financial condition and results of operations could be adversely affected.
Foresight Energy is our largest lessee, and in 2016, we derived approximately 16% of our revenues from them. We are
currently in disputes with them with respect to two of their four mining operations in which we have an interest. Foresight Energy’s
Deer Run mine (which we also refer to as our Hillsboro property) has been idled for almost two years as a result of elevated carbon
monoxide levels at the mine. Foresight Energy has declared a force majeure event at the Deer Run mine and failed to make $46.0
million in required minimum deficiency payments to us as of the date hereof. Such amount is expected to increase by $7.5 million
for each quarter during which mining operations continue to be idled. We have filed a lawsuit against Foresight Energy and Hillsboro
Energy to recover the amounts owed to us and compel them to make the required minimum deficiency payments under the lease.
We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended
period or if the mine is permanently closed, our financial condition could be adversely affected. In addition, we have also filed a
lawsuit against Foresight Energy’s Macoupin subsidiary, which has failed to comply with the terms of the coal mining, rail loadout
and rail loop leases at the Macoupin mine by incorrectly recouping previously paid minimum royalties, resulting in a cumulative $6.2
million negative cash impact to us. See "Item 3. Legal Proceedings" included elsewhere in this Annual Report on Form 10-K for
more information on our lawsuits against Foresight Energy. These ongoing disputes and further deterioration of our relationship
with our largest lessee could have a material adverse effect on our financial condition and results of operations.
Depressed coal prices have negatively affected our coal-related revenues and the value of our coal reserves. Further declines
or a continued low price environment could have an additional adverse effect on our coal-related revenues and the value of
our coal reserves.
Prices for both steam and metallurgical coal have declined substantially in recent years. Steam coal prices remain at levels
close to or below the level of operating costs for a number of our lessees. While metallurgical coal prices have improved in recent
months, we do not expect the current pricing environment to be sustained, and prices could decline substantially. The prices our
lessees receive for their coal depend upon factors beyond their or our control, including:
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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 and the demand for steel;
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•
the proximity to and capacity of transportation facilities;
• weather conditions; and
•
the effect of worldwide energy conservation measures.
Natural gas is the primary fuel that competes with steam coal for power generation. Relatively low natural gas prices have
resulted in a number of utilities switching from steam coal to natural gas to the extent that it is practical to do so. This switching
has resulted in a decline in steam coal prices, and to the extent that natural gas prices remain low, steam coal prices will also remain
low. The closure of coal-fired power plants as a result of increased governmental regulations or the inability to comply with such
regulations has also resulted in a decrease in the demand for steam coal.
Prices for metallurgical coal reached multi-year lows during 2016 due to global economic conditions. While metallurgical
coal prices have improved in recent months, we do not expect the current pricing environment to be sustained. Our lessees produce
a significant amount of the metallurgical coal that is used in both the U.S. and foreign steel industries. Since the amount of steel
that is produced is tied to global economic conditions, a continuation of current conditions or a further decline in those conditions
could result in the decline of steel, coke and metallurgical coal production. In addition, rising exports of metallurgical coal from
Australia and a strong U.S. dollar continue to have a negative effect on prices received for metallurgical coal produced in the
United States. Since metallurgical coal is priced higher than steam 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. In addition, during 2015 and 2016, a number of coal producers
filed for protection under U.S. bankruptcy laws, including several of our coal lessees. Although many of our lessees have emerged
from bankruptcies, 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.
Lower prices reduce the quantity of coal that may be economically produced from our properties, which in turn reduces our
coal-related revenues and the value of our coal reserves. Further declines or a continued low price environment could have an
additional adverse effect on our coal-related revenues or the value of our reserves. 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 the
production from our properties would reduce our revenues. The level of production is subject to operating conditions or events
beyond our or our lessees’ control including:
•
•
the inability to acquire necessary permits or mining or surface rights;
changes or variations in geologic conditions, such as the thickness of the mineral deposits and, in the case of coal, the
amount of rock embedded in or overlying the coal deposit;
• mining and processing equipment failures and unexpected maintenance problems;
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•
•
•
•
the availability of equipment or parts and increased costs related thereto;
the availability of transportation facilities and interruptions due to transportation delays;
adverse weather and natural disasters, such as heavy rains and flooding;
labor-related interruptions; and
unexpected mine safety accidents, including fires and explosions.
Under the current regulatory environment, there is substantial uncertainty relating to the ability of our coal lessees to be
issued permits necessary to conduct mining operations. The non-issuance of permits has limited the ability of our coal lessees to
open new operations, expand existing operations, and may preclude new acquisitions in which we might otherwise be involved.
We and our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising
from our or their operations. If we or our lessees are pursued for these sanctions, costs and liabilities, mining operations and, as a
result, our revenues could be adversely affected.
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VantaCore currently operates four hard rock quarries, one underground limestone mine, six sand and gravel plants, two
asphalt plants and two marine terminals. As an operator of these assets, we are exposed to risks that we have not historically been
exposed to in our mineral rights and royalties business. Such risks include, but are not limited to, prices and demand for construction
aggregates, capital and operating expenses necessary to maintain VantaCore’s operations, production levels, general economic
conditions, conditions in the local markets that VantaCore serves, inclement or hazardous weather conditions and typically lower
production levels in the winter months, permitting risk, fire, explosions or other accidents, and unanticipated geologic conditions.
Any of these risks could result in damage to, or destruction of, VantaCore’s mining properties or production facilities, personal
injury, environmental damage, delays in mining or processing, reduced revenue or losses or possible legal liability. In addition,
not all of these risks are reasonably insurable, and our insurance coverage contains limits, deductibles, exclusions and endorsements.
Our insurance coverage may not be sufficient to meet our needs in the event of loss. Any prolonged downtime or shutdowns at
VantaCore’s mining properties or production facilities or material loss could have an adverse effect on our results of operations.
Changes in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal have resulted in
and will continue to result in lower coal production by our lessees and reduced coal-related revenues.
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
proposed rules promulgated by the EPA on greenhouse 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 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.
The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" and other hazardous
air pollutants have resulted in and will continue to result in reduced demand for our coal, oil and natural gas.
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 has begun 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 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. The rule will 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. This rule is being challenged by industry participants and other parties. In February, 2016, the Supreme Court of the United
States stayed the Clean Power Plan Rule pending a decision by the District of Columbia Circuit as well as any subsequent review
by the Supreme Court.
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. Oral arguments are currently scheduled
for April 2017.
In addition to EPA’s GHG 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
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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.
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, VantaCore 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. The oil and gas industry is also subject to numerous laws and regulations. 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 the mining and oil and gas 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.
In addition to governmental regulation, private citizens’ groups have continued to be active in bringing lawsuits against coal
mine operators and landowners. Since 2012, several citizen suit group lawsuits have been filed against mine operators and
landowners for alleged violations of water quality standards resulting from ongoing discharges of pollutants from reclaimed mining
operations, including selenium and conductivity. NRP has been named as a defendant in one of these lawsuits. The citizen suit
groups have sought penalties as well as injunctive relief that would limit future discharges of these pollutants, which would result
in significant expenses for our lessees. While it is too early to determine the merits or measure the impact of these lawsuits, any
determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty
as to continuing liability for completed and reclaimed coal mine operations and could result in substantial compliance costs or
fines.
Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on our
results of operations.
The market price of soda ash directly affects the profitability of Ciner Wyoming’s soda ash production operations. If the
market price for soda ash declines, Ciner Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent,
the domestic market for soda ash have been volatile, and those markets are likely to remain volatile in the future. The prices Ciner
Wyoming receives for its soda ash depend on numerous factors beyond Ciner Wyoming’s control, including worldwide and regional
economic and political conditions impacting supply and demand. Glass manufacturers and other industrial customers drive most
of the demand for soda ash, and these customers experience significant fluctuations in demand and production costs. Competition
from increased use of glass substitutes, such as plastic and recycled glass, has had a negative effect on demand for soda ash.
Substantial or extended declines in prices for soda ash could have a material adverse effect on our results of operations. In addition,
Ciner Wyoming relies on natural gas as the main energy source in its soda ash production process. Accordingly, high natural gas
prices increase Ciner Wyoming’s cost of production and affect its competitive cost position when compared to other foreign and
domestic soda ash producers.
VantaCore operates in a highly competitive and fragmented industry, which may negatively impact prices, volumes and costs.
In addition, both commercial and residential construction are dependent upon the overall U.S. economy.
The construction aggregates industry is highly fragmented with a large number of independent local producers operating in
VantaCore’s local markets. Additionally, VantaCore also competes against large private and public companies, some of which are
significantly vertically integrated. Therefore, there is intense competition in a number of markets in which VantaCore operates.
This significant competition could lead to lower prices and lower sales volumes in some markets, negatively affecting our earnings
and cash flows.
In addition, commercial and residential construction levels generally move with economic cycles. When the economy is
strong, construction levels rise and when the economy is weak, construction levels fall. The U.S. economy is recovering from the
2008-2009 recession, but the pace of recovery is slow. Since construction activity generally lags the recovery after down cycles,
construction projects have not returned to their pre-recession levels.
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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 of mining;
•
•
•
•
•
•
•
•
•
processing and blending minerals;
expansion plans and capital expenditures;
credit risk of their customers;
permitting;
insurance and surety bonding;
acquisition of surface rights and other mineral estates;
employee wages;
transportation arrangements;
compliance with applicable laws, including environmental laws; and
• mine closure and reclamation.
A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us
the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of
our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might
not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could
be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the 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 have limited control over the activities on our properties that we do not operate and are exposed to operating risks that we
do not experience in the royalty business.
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 would result in decreased distributions to NRP. In addition, we are ultimately
responsible for operating the transportation infrastructure at Foresight’s Williamson mine, and have assumed the capital and
operating risks associated with that business. As a result of these investments, we could experience increased costs as well as
increased liability exposure associated with operating these facilities.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal,
soda ash, construction aggregates, 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 other events
could temporarily impair the ability of our lessees to supply minerals to their customers. Our lessees’ transportation providers may
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face difficulties in the future that may 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. During 2016, Ciner Wyoming shipped substantially all of its soda ash via a Union Pacific rail line. Ciner Wyoming
relies on the rail line to service its facilities under a contract that expires in 2017. 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, you should not place undue reliance on our reserve data that is included in this report.
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.
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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 units (including units held by our general partner and its affiliates).
Because the owners of our general partner, along with directors and executive officers and their affiliates, own a significant
percentage of our outstanding common units, the removal of our general partner would be difficult without the consent of both
our general partner and its affiliates.
In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to
remove our general partner or otherwise change our management:
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generally, if a person acquires 20% or more of any class of units then outstanding other than from our general partner or
its affiliates, the units owned by such person cannot be voted on any matter; and
our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information
about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of
management.
As a result of these provisions, the price at which the common units will trade may be lower because of the absence or
reduction of a takeover premium in the trading price.
The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of
additional common units in the future, which could result in substantial dilution of our common unitholders’ ownership
interests.
The preferred units are a new class of partnership interests that 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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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.
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We may issue additional common units or preferred units without 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 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 unitholder approval (subject to applicable
NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank will have the following
effects:
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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.
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.
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.
Conflicts of interest could arise among our general partner and us or the unitholders.
These conflicts may include the following:
• Excluding our VantaCore business, we do not have any employees and we rely solely on employees of affiliates of the
general partner;
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under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the
partnership;
the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly
distributions to unitholders;
the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its
assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach
its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without
limiting the general partner’s liability;
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•
•
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, as a result of the purchase of the Preferred Units, 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.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject
to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as
a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level
taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common 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, 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 you would generally
be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because
tax would be imposed upon us as a corporation, our cash available for distribution to you 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 common
unitholders, likely causing a substantial reduction in the value of our common 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 you.
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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 common
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, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning
of Section 7704 of the Internal Revenue Code of 1986, as amended (the "Final Regulations") were published in the Federal Register.
The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We
anticipate that we will continue to meet the qualifying income exception for publicly traded partnership under the Final Regulations.
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 common units.
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated
as a result of future legislation.
Changes to U.S. federal income tax laws have been proposed in a prior session of Congress that would eliminate certain key
U.S. federal income tax preferences relating to coal exploration and development. These changes include, but are not limited to
(i) repealing capital gains treatment of coal and lignite royalties, (ii) eliminating current deductions and 60-month amortization
for exploration and development costs relating to coal and other hard mineral fossil fuels, (iii) repealing the percentage depletion
allowance with respect to coal properties, and (iv) excluding from the definition of domestic production gross receipts all gross
receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof.
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 common units.
You are required to pay taxes on your share of our income even if you do not receive any cash distributions from us. Your share
of our portfolio income may be taxable to you even though you 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, you are required to pay any federal income taxes and, in some cases, state and local income taxes on your
share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us
equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.
For unitholders subject to the passive loss rules, our current operations include portfolio activities (such as our coal and
mineral royalties business) and passive activities (such as our soda ash and aggregates businesses). 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 royalties business, (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, your share of our portfolio income may be subject to federal income tax, regardless of other losses you may receive from
us.
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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 unitholders, and income tax
liabilities arising therefrom may exceed any distributions made with respect to your units.
In response to current market conditions, 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, you 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. Unitholders may be allocated income and
gain from these transactions, and income tax liabilities arising therefrom may exceed any distributions we make to you. 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. 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. 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 common units may be adversely impacted and
the cost of any IRS contest will reduce our cash available for distribution to you.
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 common units and the price
at which they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders and our general
partner because the costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some
states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit
adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit
adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties
and interest) resulting from such audit adjustment directly from us. To the extent possible under the new 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 Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to
have our 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. These rules are
not applicable for tax years beginning on or prior to December 31, 2017.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and
your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in
a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common
units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in
those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount
realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion
and depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities,
if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
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Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse
tax consequences to them.
Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts
(known as IRAs), and non-U.S. persons raise issues unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business
taxable income and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be reduced by withholding
taxes imposed at the highest applicable effective tax rate applicable to non-U.S. persons, and non-U.S. persons will be required
to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-
U.S. person, you should consult your tax advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units
purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation
and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits
or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or
result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month
based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular
unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss
and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units
each month based upon the ownership of our common units on the first day of each month (the "Allocation Date"), instead of on
the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital
additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other
extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow
a similar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we
have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income,
gain, loss and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of
common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax
purposes as a partner with respect to those common 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 common units are the subject of a securities loan may be considered as having disposed of the loaned common
units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and
any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders
desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their common units are urged to
modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the
termination of us as a partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of
50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether
the 50% threshold has been met, multiple sales of the same interest will be counted only once. The partnership technically terminated
on August 31, 2016, as a result of the sale or exchange of 50% or more of our capital and profits interest during the prior twelve
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month period. Any technical termination, such as the one occurring in 2016, would, among other things, result in the closing of
our taxable year for all unitholders, which would result in our filing two tax returns for one calendar year and could result in a
significant deferral of depreciation deductions allowable in computing taxable income for the applicable year. In the case of a
unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than
twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our
termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it
would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were
treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable
to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that
has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to
provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
As a result of investing in our common units, you are subject to state and local taxes and return filing requirements in jurisdictions
where we operate or own or acquire property.
In addition to federal income taxes, you 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 you do not live in any of those jurisdictions. You 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, you 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 your responsibility to file all U.S. federal, state and local tax returns.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate
results of these proceedings cannot be predicted with certainty, we believe these claims will not have a material effect on our
financial position, liquidity or operations.
In November 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the
Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of
contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late
March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled.
In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels.
We believe the force majeure claim by Hillsboro has no merit and we are vigorously pursuing recovery against them. However,
the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency
payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with
respect to the second, third and fourth quarters of 2015 and each quarter of 2016 resulted in a cumulative $46.0 million negative
cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not
currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or
if the mine is permanently closed, our financial condition could be adversely affected.
In April 2016, we filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin
County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail
loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its
recoupable balance and failure to make payments in accordance with these lease agreements has resulted in a cumulative $6.2
million negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount
has been recorded.
36
For more information regarding certain other legal proceedings involving NRP, see "Note 14. Commitments and
Contingencies" included in the Notes to Consolidated Financial Statements in "Item 8. Financial Statements and Supplementary
Data" included elsewhere in this Annual Report on Form 10-K.
ITEM 4. MINE SAFETY DISCLOSURES
The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in
Exhibit 95.1 to this Annual Report on Form 10-K.
37
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
NRP Common Units and Cash Distributions
Our common units are listed and traded on the NYSE under the symbol "NRP". As of February 1, 2017, there were
approximately 26,500 beneficial and registered holders of our common units. The computation of the approximate number of
unitholders is based upon a broker survey.
The following table sets forth the high and low sales prices per common unit, as reported on the NYSE Composite Transaction
Tape from January 1, 2015 to December 31, 2016, and the quarterly cash distribution declared and paid with respect to each quarter
per common unit. The information presented in the tables below has been adjusted to give retroactive effect to the one-for-ten
reverse unit split that was effective on February 17, 2016.
2015
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2015 Distributions
2016 Distributions
Price Range
Cash Distribution History
High
Low
Per
Unit
Record
Date
Payment
Date
$
$
$
$
$
$
$
$
98.10
74.50
38.00
29.90
13.86
18.92
29.85
40.00
$
$
$
$
$
$
$
$
63.80
36.10
22.10
10.00
5.00
7.13
13.97
25.11
$
$
$
$
$
$
$
$
Cash Distributions to Partners
0.90
0.90
0.45
0.45
0.45
0.45
0.45
0.45
5/5/2015
8/5/2015
11/5/2015
2/5/2016
5/5/2016
8/5/2016
11/7/2016
2/7/2017
5/14/2015
8/14/2015
11/13/2015
2/12/2016
5/13/2016
8/12/2016
11/14/2016
2/14/2017
General
Partner (1)
Limited
Partners (2)
(in thousands)
Total
Distributions
$
$
1,434
451
$
$
70,324
22,014
$
$
71,758
22,465
(1) Represents distributions on our general partner’s 2% general partner interest in us.
(2) Includes $0.9 million and $0.3 million distributions to our general partner on 156,000 common units beneficially owned
by our general partner in 2015 and 2016, respectively.
38
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."
Total revenues and other income
Asset impairments
Income (loss) from operations
Net income (loss) from continuing
operations
Net income from continuing operations
excluding impairments (1)
Net income (loss) from discontinued
operations
Net income (loss)
Per common unit amounts (basic and
diluted)
Net income (loss) from continuing
operations
Net income (loss) from discontinued
operations
Net income (loss)
Distributions paid
Average number of common units
outstanding (2)
Net cash provided by (used in)
Operating activities of continuing
operations
Investing activities of continuing
operations
Financing activities of continuing
operations
Distributable Cash Flow (1)
Adjusted EBITDA (1)
Cash and cash equivalents
Total assets
Long-term debt
Partners’ capital
For the Years Ended December 31,
2016
2015
2014
2013
2012
(in thousands, except per unit data)
400,059
16,926
185,745
95,214
112,140
1,678
96,892
7.65
0.13
7.78
1.80
12,232
100,643
59,943
$
$
$
$
$
$
$
$
$
$
$
$
$
$
439,648
384,545
$
(170,427) $
350,918
26,209
176,140
(260,171) $
96,713
124,374
$
122,922
(311,549) $
(571,720) $
12,117
108,830
(20.78) $
8.37
(24.97) $
(45.75) $
$
2.70
1.05
9.42
14.00
$
$
$
$
$
$
$
$
$
$
$
352,739
734
233,740
169,621
170,355
2,457
172,078
15.17
0.22
15.39
22.00
$
$
$
$
$
$
$
$
$
$
$
379,147
2,568
267,165
213,355
215,923
—
213,355
19.70
—
19.70
22.00
12,232
11,326
10,958
10,603
168,512
6,985
$
$
192,164
$
246,891
$
271,408
(169,512) $
(230,436) $
(212,733)
(161,419) $
$
271,415
(183,264) $
$
176,617
(65,986) $
$
196,929
(73,574) $
$
306,690
255,471
40,371
1,444,681
987,400
151,530
$
$
$
$
$
262,639
41,204
1,670,035
1,206,611
76,336
$
$
$
$
$
263,871
48,971
2,430,819
1,270,573
720,155
$
$
$
$
$
328,690
92,305
1,980,354
1,072,962
616,789
$
$
$
$
$
(124,173)
296,106
328,116
149,424
1,760,381
892,986
617,447
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1) See "—Non-GAAP Financial Measures" below.
(2) The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective
on February 17, 2016.
39
Non-GAAP Financial Measures
Distributable Cash Flow
Our Distributable Cash Flow ("DCF") represents net cash provided by operating activities of continuing operations, plus
returns of unconsolidated equity investments, proceeds from sales of assets, including those included in discontinued operations,
and returns of long-term contract receivables—affiliate; less maintenance capital expenditures and distributions to non-controlling
interest. DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows
from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies. DCF is a
supplemental liquidity measure used by our management and by external users of our financial statements, such as investors,
commercial banks, research analysts and others to assess the Partnership's ability to make cash distributions to our unitholders and
our general partner and repay debt. The following table (in thousands) reconciles net cash provided by operating activities of
continuing operations (the most comparable GAAP financial measure) to Distributable Cash Flow for the years ended December
31, 2016, 2015, 2014, 2013 and 2012:
Net cash provided by operating
activities of continuing operations
Add: return of unconsolidated equity
investment
Add: proceeds from sale of PP&E
Add: proceeds from sale of mineral
rights
Add: proceeds from sale of assets
included in discontinued operations
Add: return on long-term contract
receivables—affiliate
Less: maintenance capital
expenditures (1)
2016
2015
2014
2013
2012
Year Ended December 31,
$
100,643
$
168,512
$
192,164
$
246,891
$
271,408
—
1,350
61,033
109,872
2,968
—
11,024
3,505
—
2,463
3,633
1,006
412
—
1,904
(4,451)
(6,143)
(1,216)
48,833
—
10,929
—
2,558
—
—
11,277
13,545
—
2,669
—
Less: distributions to non-controlling
interest
—
Distributable Cash Flow
$
271,415
$
(2,744)
176,617
$
(974)
196,929
$
(2,521)
306,690
$
(2,793)
296,106
(1) Maintenance capital expenditures primarily consist of costs to maintain the long-term productive capacity of VantaCore.
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, gain on reserve swaps and income to non-controlling interest; plus distributions
from equity earnings in unconsolidated investment, interest expense, depreciation, depletion and amortization and asset
impairments.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or
loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance
presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There
are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of
certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different
companies and the different methods of calculating Adjusted EBITDA reported by different companies.
Adjusted EBITDA is a supplemental performance measure used by our management and by external users of our financial
statements, such as investors, commercial banks, research analysts and others to assess the financial performance of our assets
without regard to financing methods, capital structure or historical cost basis.
40
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP
financial measure) to Adjusted EBITDA for the years ended December 31, 2016, 2015, 2014, 2013 and 2012:
Net income (loss) from continuing
operations
Less: equity earnings from
unconsolidated investment
Less: gain on reserve swaps
Add: distributions from equity
earnings in unconsolidated investment
Add: interest expense
Add: depreciation, depletion and
amortization
Add: asset impairments
Adjusted EBITDA
2016
2015
2014
2013
2012
Year Ended December 31,
$
95,214
$
(260,171) $
96,713
$
169,621
$
213,355
(40,061)
—
46,550
90,570
(49,918)
(9,290)
46,795
89,762
(41,416)
(5,690)
46,638
79,523
(34,186)
(8,149)
72,946
64,357
46,272
16,926
255,471
$
60,916
384,545
262,639
$
61,894
26,209
263,871
$
63,367
734
328,690
$
$
—
—
—
53,972
58,221
2,568
328,116
Adjusted EBITDA presented in the table above differs from the EBITDDA definitions contained in Opco’s debt agreements.
See Note 11. "Debt and Debt—Affiliate" included in the Notes to Consolidated Financial Statements in Item 8. "Financial Statements
and Supplementary Data" included elsewhere in this Annual Report on Form 10-K for a description of Opco’s debt agreements.
Net Income from Continuing Operations Excluding Impairments
Net income from continuing operations excluding impairments is a non-GAAP financial measure that we define as net income
(loss) from continuing operations plus asset impairments. Net income from continuing operations excluding impairments, as used
and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of
performance calculated in accordance with GAAP. Net income excluding impairments should not be considered in isolation or as
a substitute for operating income (loss), net income (loss), cash flows provided by operating, investing and financial activities, or
other income or cash flow statement data prepared in accordance with GAAP. Our management team believes net income excluding
impairments is useful in evaluating our financial performance because asset impairments are irregular non-cash charges and
excluding these from net income allows us to better compare results period-over-period.The following table (in thousands)
reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to net income excluding
impairment for the years ended December 31, 2016, 2015, 2014, 2013 and 2012:
2016
2015
Year Ended December 31,
2014
2013
2012
Net income (loss) from continuing
operations
Add: asset impairments
Net income from continuing
operations excluding impairments
$
$
$
95,214
16,926
(260,171) $
384,545
$
96,713
26,209
$
169,621
734
213,355
2,568
112,140
$
124,374
$
122,922
$
170,355
$
215,923
41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Intr
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. References to NRP
Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation ("NRP Finance") is a
wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes due 2018 (the "2018 Notes") and the
10.50% senior notes due 2022 (the "2022 Notes").
42
Executive Overview
We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a
diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates
and other natural resources. Our common units trade on the New York Stock Exchange under the symbol "NRP".
Our business is organized into three operating segments:
Coal Royalty and Other—consists primarily of coal royalty and coal related transportation and processing assets. Other
assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. Our coal reserves are primarily located
in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of
states across the United States. Our oil and gas royalty assets are 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. We receive regular quarterly distributions
from this business.
VantaCore—consists of our construction materials business that operates hard rock quarries, an underground limestone
mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee,
Kentucky and Louisiana.
For the year ended December 31, 2016, our financial results included (in thousands):
Revenues and other income
Net income from continuing operations
Adjusted EBITDA (1)
Operating cash flow provided by continuing operations
Investing cash flow provided by continuing operations
Financing cash flow (used in) continuing operations
Distributable Cash Flow ("DCF") (1)
$
$
$
$
$
$
$
400,059
95,214
255,471
100,643
59,943
(161,419)
271,415
(1) See "—Results of Operations" below for additional information regarding non-GAAP financial measures and
reconciliations to the most comparable GAAP financial measures.
2017 Recapitalization Transactions
We have been pursuing or considering a number of actions in order to mitigate the effects of adverse market developments
and scheduled debt principal payments since April 2015 when we announced our long-term strategic plan to strengthen our balance
sheet and enhance our liquidity. On March 2, 2017, we completed the following transactions that achieved these objectives and
will ultimately reposition the partnership for long-term growth:
•
•
•
the issuance of $250 million of a new class of 12.0% preferred units representing limited partner interests in NRP,
together with warrants to purchase common 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");
the exchange of $241 million of our 9.125% Senior Notes due 2018 (the "2018 Notes") for $241 million of a new
series of 10.500% Senior Notes due 2022 (the "2022 Notes"), and the sale of $105 million of additional 2022 Notes
in exchange for cash proceeds; and
the extension of Opco’s revolving credit facility (the "Opco Credit Facility") to April 2020, with commitments
thereunder reduced to $180 million.
We used a portion of the proceeds from these transactions to repay Opco’s revolving credit facility in full and pay all fees
and expenses associated with the transactions described above. We will also use a portion of the proceeds to redeem the remaining
2018 Notes. On March 3, 2017, we delivered a notice of partial redemption for $90.0 million of our outstanding 2018 Notes at a
43
redemption price of 104.563%, plus accrued and unpaid interest to the redemption date. This partial redemption of the 2018 Notes
is expected to occur on April 3, 2017. We will redeem all of the remaining 2018 Notes within 60 days after October 1, 2017 at
the then-applicable price and pay all accrued and unpaid interest thereon.
For more information on these transactions, including the terms of the preferred units, warrants and 2022 Notes, see "—
Liquidity and Capital Resources—2017 Recapitalization Transactions."
2016 Asset Sales
Prior to completion of these recapitalization transactions, we had been pursuing or considering a number of actions, including
dispositions of assets, in order to mitigate the effects of adverse market developments and scheduled debt principal payments. As
part of this plan, we sold assets during the year ended December 31, 2016, for total gross proceeds of $181.0 million that consisted
of the following:
• Oil and gas working interest in the Williston Basin for $116.1 million gross sales proceeds that marked our exit from
the non-operated oil and gas working interest business.
• Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin
for $36.4 million gross sales proceeds.
• Aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee
for $10.0 million gross sales proceeds.
• Mineral reserves in multiple sale transactions for cumulative $17.3 million of gross sales proceeds. These amounts
primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas
royalty interests. Additional asset sales during the year included sales of land and plant and equipment for $1.2 million
of gross proceeds.
Current Liquidity
As of December 31, 2016, we had a total of $40.4 million of cash and cash equivalents. During the year ended December 31,
2016, we reduced our debt by approximately $248.1 million by repaying $85.0 million of the NRP Oil and Gas reserve based
lending facility in full (the "RBL Facility"), $82.9 million of the Opco Private Placement Notes (as defined below), $80.0 million
of the Opco Credit Facility and $0.2 million of Opco's utility local improvement obligation.
In March 2017, we increased our liquidity through the completion of the recapitalization transactions described above,
including by repaying borrowings outstanding under the Opco Credit Facility in full. In addition to enhancing our liquidity, these
recapitalization transactions reduced our 2018 debt maturities by $575 million through the extension of debt principal payments
from 2018 to 2020 and 2022. Even with these meaningful improvements to our liquidity and balance sheet, we continue to have
substantial debt outstanding and intend to continue to use cash from operations to deleverage our balance sheet over time. While
we have a diversified portfolio of assets, we face challenges in coal and other commodity markets. Our going concern analysis
included an analysis of these relevant conditions and events and our ability to meet our obligations and remain in compliance with
our debt covenants within one year after the issuance date of these financial statements. We expect that we will meet all of our
obligations, including scheduled principal and interest payments on our debt and required distributions on the preferred units,
comply with all covenants contained in our debt agreements and that we will continue as a going concern.
44
Current Results/Market Outlook
Coal Royalty and Other Business Segment
For the year ended December 31, 2016, our Coal Royalty and Other business segment financial results included the following
(in thousands):
Revenues and other income
Net income from continuing operations
Adjusted EBITDA (1)
Operating cash flow provided by continuing operations
Investing cash flow provided by continuing operations
Financing cash flow provided by continuing operations
DCF (1)
$
$
$
$
$
$
$
239,183
161,816
209,443
134,490
65,057
16
199,547
(1) See "—Results of Operations" below for additional information regarding non-GAAP financial measures and
reconciliations to the most comparable GAAP financial measures.
In the fourth quarter of 2016, we began to realize the benefits of the dramatic increase in metallurgical coal prices as well
as the improvement in the thermal coal markets. A number of our lessees were able to take advantage of the improved markets
and lock in tonnage commitments for 2017 at substantially higher prices than they realized in 2016. While spot metallurgical prices
have recently retreated from the highs reached in the fourth quarter, we believe that that global supply/demand dynamic will support
long-term metallurgical coal prices well above the lows hit in the first half of 2016. We derived approximately 37% of our coal
royalty revenues and approximately 35% of the related production from metallurgical coal during the year ended December 31,
2016. The domestic thermal coal markets have also shown modest improvements, as production cuts over the last year have
rationalized coal stockpiles. Although a mild winter has tempered demand for thermal coal, natural gas prices remain higher than
2016, causing thermal coal to be more competitive for electricity generation as compared to recent years. In addition, we expect
the actions of the Trump Administration to ease the regulatory burdens on the coal industry, reducing the production costs and
increasing the competitiveness of our lessees against natural gas. Despite these improvements, producers of Central Appalachian
thermal coal continue to face challenges, as many still have large debt burdens and their production costs remain high relative to
sales prices. We have successfully navigated the bankruptcies of several of our lessees and have had substantially all of our leases
assumed or assigned and received substantially all past-due amounts in these bankruptcies.
Production from our Illinois Basin properties decreased by 27% during the year ended December 31, 2016 as compared to
the year ended December 31, 2015. Substantially all of the decrease is attributable to the idling of Foresight Energy's Deer Run
mine (which we also refer to as our Hillsboro property) during 2016. In July 2015, we received a notice from Foresight Energy
declaring a force majeure event at the Deer Run mine after elevated levels of carbon monoxide were detected. We believe Foresight's
claim of force majeure has no merit and we are vigorously pursuing our claims against them through a lawsuit filed in November
2015. However, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us quarterly
minimum deficiency payments with respect to the Deer Run mine until mining resumes. Under the lease for the Deer Run mine,
Foresight Energy is required to make minimum deficiency payments to us of $7.5 million per quarter, or $30.0 million per year.
Foresight Energy’s failure to make the deficiency payments with respect to the second, third and fourth quarters of 2015 and all
four quarters of 2016 resulted in a cumulative negative cash impact to us of $46.0 million. Such amount will increase for each
quarter during which mining operations continue to be idled. Foresight Energy is continuing efforts to reenter the mine, but we
do not know when, or if, mining activities at the Deer Run mine will recommence.
45
Soda Ash Business Segment
For the year ended December 31, 2016, our Soda Ash business segment financial results included the following (in thousands):
Revenues and other income
Net income from continuing operations
Adjusted EBITDA (1)
Operating cash flow provided by continuing operations
Financing cash flow used by continuing operations
DCF (1)
$
$
$
$
$
$
40,061
40,061
46,550
46,550
(7,229)
46,550
(1) See "—Results of Operations" below for additional information regarding non-GAAP financial measures and
reconciliations to the most comparable GAAP financial measures.
Income from our trona mining and soda ash refinery investment was lower year-over-year for the year ended December 31,
2016. This decrease is primarily related to lower international prices compared to the prior year, in addition to higher royalty and
G&A costs. These decreases were partially offset by an increase in soda ash volumes sold compared to the prior year. Ciner
Resources LP, our partner that controls and operates Ciner Wyoming, is a publicly traded master limited partnership that depends
on distributions from Ciner Wyoming in order to make distributions to its public unitholders.
VantaCore Business Segment
For the year ended December 31, 2016, our VantaCore business segment financial results included the following (in
thousands):
Revenues and other income
Net income from continuing operations
Adjusted EBITDA (1)
Operating cash flow provided by continuing operations
Investing cash flow used by continuing operations
Financing cash flow used by continuing operations
DCF (1)
$
$
$
$
$
$
$
120,815
4,438
20,009
20,400
(5,114)
(1,825)
16,243
(1) See "—Results of Operations" below for additional information regarding non-GAAP financial measures and
reconciliations to the most comparable GAAP financial measures.
VantaCore’s construction aggregates mining and production business is largely dependent on the strength of the local markets
that it serves. VantaCore’s Laurel Aggregates operation in southwestern Pennsylvania serves producers and oilfield service
companies operating in the Marcellus and Utica Shales and was impacted during the year ended December 31, 2016 by the slowing
pace of exploration and development of natural gas in those areas due to low natural gas prices. Increased local construction activity
partially offset these declines during the year ended December 31, 2016, but we expect that Laurel’s business will continue to be
impacted by decreased natural gas development activities. While VantaCore's production and revenues have declined in 2016
compared to 2015, its cost management efforts have enabled the business to maintain its profitability.
Discontinued Operations
In July 2016, NRP Oil and Gas closed on the sale of its non-operated oil and gas working interest assets in the Williston
Basin for $116.1 million in gross sales proceeds. Our exit from our non-operated oil and gas working interest business represented
a strategic shift to reduce debt and focus on our soda ash, coal royalty and construction aggregates business segments. As a result,
we have classified the assets and liabilities, operating results and cash flows of our non-operated oil and gas working interest assets
as discontinued operations in our consolidated financial statements for all periods presented.
46
Results of Operations
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Revenues and Other Income
Revenues and other income decreased $39.5 million, or 9%, from $439.6 million in the year ended December 31, 2015 to
$400.1 million in the year ended December 31, 2016. The following table shows our diversified sources of natural resource revenues
and other income by business segment for the year ended December 31, 2016 and 2015 (in thousands except for percentages):
2016
Revenues and other income
Percentage of total
2015
Revenues and other income
Percentage of total
Coal Royalty and
Other
Soda Ash
VantaCore
Total
$
$
239,183
$
40,061
$
120,815
$
400,059
60%
10%
30%
250,717
$
49,918
$
139,013
$
439,648
57%
11%
32%
The changes in revenue and other income is discussed for each of the our business segments below:
Coal Royalty and Other
Revenues and other income related to our Coal Royalty and Other segment decreased $11.5 million, or 5%, from $250.7
million in the year ended December 31, 2015 to $239.2 million in the year ended December 31, 2016.
47
The table below presents coal production and coal royalty revenues (including affiliates) derived from our major coal
producing regions and the significant categories of other coal royalty and other revenues:
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
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
Transportation and processing fees
Property tax revenue
Wheelage
Coal override revenue
Lease assignment fee
Gain on reserve swap
Hard mineral royalty revenues
Oil and gas royalty revenues
Other
Total other revenues
Coal royalty and other income
Gain on coal royalty and other segment asset sales
Total coal royalty and other segment revenues and other income
For the Year Ended December 31,
2016
2015
Increase
(Decrease)
Percentage
Change
(In thousands, except percent and per ton data)
(Unaudited)
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
2,667
48,119
10,660
61,446
29,680
10,637
1
101,764
64,591
19,336
10,457
2,374
2,281
—
—
3,163
3,537
2,612
108,351
210,115
29,068
239,183
$
$
$
$
$
$
9,562
16,862
3,803
30,227
11,173
4,905
740
47,045
0.28
3.85
4.57
3.94
2.54
3.47
2,672
64,877
17,390
84,939
44,063
12,443
2,570
144,015
15,489
22,033
11,258
3,166
2,920
21,000
9,290
8,090
4,364
2,156
99,766
243,781
6,936
250,717
$
$
$
$
$
$
$
$
$
$
$
$
(7,250)
(3,640)
(1,027)
(11,917)
(3,057)
(1,124)
(740)
(16,838)
0.87
(0.21)
(0.73)
(0.28)
0.27
(0.19)
(5)
(16,758)
(6,730)
(23,493)
(14,383)
(1,806)
(2,569)
(42,251)
49,102
(2,697)
(801)
(792)
(639)
(21,000)
(9,290)
(4,927)
(827)
456
8,585
(33,666)
22,132
(11,534)
(76)%
(22)%
(27)%
(39)%
(27)%
(23)%
(100)%
(36)%
311 %
(5)%
(16)%
(7)%
11 %
(5)%
— %
(26)%
(39)%
(28)%
(33)%
(15)%
(100)%
(29)%
317 %
(12)%
(7)%
(25)%
(22)%
(100)%
(100)%
(61)%
(19)%
21 %
9 %
(14)%
319 %
(5)%
Total coal production decreased 16.8 million tons, or 36%, from 47.0 million tons in the year ended December 31, 2015 to
30.2 million tons in the year ended December 31, 2016. Total coal royalty revenues decreased $42.3 million, or 29%, from $144.0
million in the year ended December 31, 2015 to $101.8 million in the year ended December 31, 2016. Total coal production and
coal royalty revenue decreases were driven by downward pressure in the coal markets as described above, with Central Appalachian
thermal coal producers in particular continuing to face challenges, as their production costs remain high relative to sales prices.
Total other revenues increased $8.6 million in 2016 compared to 2015 primarily as a result of the agreements with certain
lessees to either modify or terminate existing coal related leases that resulted in the recognition of $40.5 million of deferred revenue.
This increase was partially offset by non-recurring revenue transactions in 2015 that included $21.0 million in lease assignment
fees and $9.3 million gain on reserve swap. Other revenues were also decreased $4.9 million in 2016 primarily as a result of the
sale of our aggregates royalty assets in the first quarter of 2016.
48
Gain on coal royalty and other segment asset sales increased $22.1 million primarily as a result of the following asset sales
during the first quarter of 2016:
1) Oil and gas royalty and overriding royalty interests 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 we recorded an $18.6 million gain from
this sale.
2) Aggregate 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
we recorded a $1.5 million gain from this sale.
Soda Ash
Revenues and other income related to our equity investment in Ciner Wyoming decreased $9.8 million, or 20%, from $49.9
million in the year ended December 31, 2015 to $40.1 million in the year ended December 31, 2016. This decrease is primarily
related to lower international prices compared to the prior year, in addition to higher royalty and G&A costs. These decreases were
partially offset by an increase in soda ash volumes sold compared to the prior year.
VantaCore
Revenues and other income related to our VantaCore segment decreased $18.2 million, or 13%, from $139.0 million in the
year ended December 31, 2015 to $120.8 million in the year ended December 31, 2016. This decrease is primarily due to a decrease
in construction aggregates and brokered stone revenue as well as lower delivery and fuel income year-over-year. Tonnage sold by
the VantaCore segment decreased 0.4 million tons, or 5% from 7.4 million tons in the year ended December 31, 2015 to 7.0 million
tons in the year ended December 31, 2016 as a result of decreased construction aggregates demand in the oil and gas services
sector that was partially offset by increased aggregates sales into the construction market.
Operating and Maintenance Expenses (including affiliates)
Operating and maintenance expenses (including affiliates) decreased $21.8 million, or 14%, from $152.3 million in the year
ended December 31, 2015 to $130.5 million in the year ended December 31, 2016. This decrease is primarily related to the
following:
VantaCore
Operating and maintenance expenses (including affiliates) in our VantaCore segment decreased $16.2 million, or 14% from
$116.9 million in the year ended December 31, 2015 to $100.7 million in the year ended December 31, 2016. This decrease is
primarily due to the decline in materials cost as a result of the decrease in construction aggregates and brokered stone volume
year-over-year due to reduced demand in the oil and gas sector and a decrease in delivery and fuel costs due to the lower construction
aggregates production and brokered stone purchases year-over-year partially and effective variable cost management.
Depreciation, Depletion and Amortization ("DD&A") Expense
DD&A expense decreased $14.6 million, or 24%, from $60.9 million in the year ended December 31, 2015 to $46.3 million
in the year ended December 31, 2016. This decrease is primarily related to the reduced cost basis of our coal and aggregates royalty
mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in coal royalty
production year-over-year.
General and Administrative (including affiliates) ("G&A") Expense
Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized
treasury and accounting. These costs increased $8.3 million, or 67%, from $12.3 million in the year ended December 31, 2015 to
$20.6 million in the year ended December 31, 2016. This increase is primarily related to increased legal and consulting fees
associated with the implementation of our long-term plan to strengthen our balance sheet, reduce debt and enhance our liquidity
and increased LTIP expense as a result of our unit price increasing in 2016 compared to decreasing unot price in 2015 and the
accelerated recognition of our LTIP awards granted in 2016
49
Asset Impairments
Asset impairments decreased $367.6 million, or 96%, from $384.5 million in the year ended December 31, 2015 to $16.9
million in the year ended December 31, 2016. We recorded the following asset impairments during the years ended December 31,
2016 and 2015 (in thousands):
Impaired Assets
Coal Royalty and Other
Mineral Rights
Plant and Equipment
Total Coal Royalty and Other Impairment
VantaCore
Plant and Equipment
Goodwill
Total VantaCore Impairment
Total impairment
Coal Royalty and Other
For the Year Ended
December 31,
2016
2015
$
$
$
$
$
13,801
2,060
15,861
1,065
—
1,065
16,926
$
$
$
$
$
371,397
6,930
378,327
692
5,526
6,218
384,545
Asset impairments decreased $362.4 million, or 96%, from $378.3 million in the year ended December 31, 2015 to $15.9
million in the year ended December 31, 2016. This decrease is primarily related to $257.5 million in coal property impairment,
$70.5 million in oil and gas property impairment and $43.4 million in aggregate property impairment recorded during the year
ended December 31, 2015 as compared to $12.1 million in coal property impairment and $1.7 million in aggregate property
impairment recorded during the year ended December 31, 2016. The impairments in 2015 primarily resulted from the continued
deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand,
sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry.
VantaCore
Asset impairments decreased $5.1 million, or 82%, from $6.2 million in the year ended December 31, 2015 to $1.1 million
in the year ended December 31, 2016. This decrease is primarily related to the $5.5 million write off of goodwill during the year
ended December 31, 2015.
Income (Loss) from Discontinued Operations
Income from discontinued operations increased $313.2 million, from a loss of $311.5 million in the year ended December 31,
2015 to income of $1.7 million in the year ended December 31, 2016. The change in income (loss) from discontinued operations
is primarily related to the $297.0 million asset impairments recorded in 2015, the sale of our non-operated oil and gas working
interest assets that was completed in July 2016 with an effective date of April 1, 2016 and the $8.3 million gain on sale for the
year ended December 31, 2016.
50
Adjusted EBITDA (Non-GAAP Financial Measure)
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP
financial measure) to Adjusted EBITDA by business segment for the years ended December 31, 2016 and 2015:
Operating Segments
Soda Ash
VantaCore
Corporate
and
Financing
Total
For the Year Ended
December 31, 2016
Net income (loss) from continuing operations
Less: equity earnings from unconsolidated investment
Add: distributions from unconsolidated investment
Add: interest expense
Add: depreciation, depletion and amortization
Add: asset impairment
Adjusted EBITDA
Coal Royalty
and Other
$ 161,816
—
—
—
31,766
15,861
$ 209,443
$
$
40,061
(40,061)
46,550
—
—
—
46,550
December 31, 2015
Net income (loss) from continuing operations
$ (208,248) $
Less: equity earnings from unconsolidated investment
Less: gain on reserve swap
Add: distributions from unconsolidated investment
Add: interest expense
Add: depreciation, depletion and amortization
Add: asset impairment
Adjusted EBITDA
—
(9,290)
—
—
45,338
378,327
49,918
(49,918)
—
46,795
—
—
—
$ 206,127
$
46,795
$
22,047
$
$
$
4,438
—
—
—
14,506
1,065
20,009
251
—
—
—
15,578
6,218
$ (111,101) $
95,214
(40,061)
46,550
90,570
46,272
16,926
$ (20,531) $ 255,471
—
—
90,570
—
—
—
$ (102,092) $ (260,171)
(49,918)
(9,290)
46,795
—
89,762
—
89,762
60,916
—
384,545
$ (12,330) $ 262,639
Adjusted EBITDA decreased $7.1 million, or 3%, from $262.6 million in the year ended December 31, 2015 to $255.5
million in the year ended December 31, 2016. The decrease is primarily a result of $42.3 million in reduced coal royalty revenue
resulting from decreased coal production and coal royalty revenue per ton driven by the continued pressure on U.S. coal producers
as described above, $21.0 million in non-recurring 2015 lease assignment fees, $4.9 million of reduced aggregates royalty revenue
in 2016 due to decreased 2016 aggregates production and sales and $8.3 million of additional G&A expense in 2016 compared to
2015 as described above. These decreases were partially offset by a $49.1 million increase in minimums recognized as revenue
primarily as a result of coal lease modifications or terminations that resulted in our lessee forfeiting their minimum royalty balances
and $22.2 million of additional gains on asset sales as compared to the same period in 2015. "Item 6. Selected Financial Data—
Non-GAAP Financial Measures—Adjusted EBITDA" for an explanation of Adjusted EBITDA.
51
Distributable Cash Flow (Non-GAAP Financial Measure)
The following table (in thousands) presents the three major categories of the statement of cash flows by business segment
for the years ended December 31, 2016 and 2015:
December 31, 2016
For the Year Ended
Net cash provided by (used in) operating activities of
continuing operations
Net cash provided by (used in) investing activities of
continuing operations
Net cash provided by (used in) financing activities of
continuing operations
December 31, 2015
Net cash provided by (used in) operating activities of
continuing operations
Net cash provided by (used in) investing activities of
continuing operations
Net cash provided by (used in) financing activities of
continuing operations
Operating Segments
Coal
Royalty
and Other
Soda Ash
VantaCore
Corporate
and
Financing
Total
$ 134,490
$
46,550
$
20,400
$ (100,797) $ 100,643
65,057
—
(5,114)
—
59,943
16
(7,229)
(1,825)
(152,381)
(161,419)
$ 204,934
$
43,029
$
23,605
$ (103,056) $ 168,512
15,805
(2,744)
—
—
(8,820)
—
6,985
— (180,520)
(183,264)
52
The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial
measure) by business segment to DCF for the years ended December 31, 2016 and 2015:
For the Year Ended
December 31, 2016
Net cash provided by (used in) operating activities of
continuing operations
Add: proceeds from sale of PP&E
Add: proceeds from sale of mineral rights
Add: proceeds from sale of assets included in
discontinued operations
Add: return on long-term contract receivables—
affiliate
Less: maintenance capital expenditures
Distributable Cash Flow
December 31, 2015
Operating Segments
Coal Royalty
and Other
Soda Ash
VantaCore
Corporate
and
Financing
Total
$
$ 134,490
1,084
61,033
$
46,550
—
—
20,400
266
—
$ (100,797) $ 100,643
1,350
61,033
—
—
—
—
—
—
109,872
2,968
(28)
$ 199,547
$
—
—
46,550
$
—
(4,423)
16,243
—
—
2,968
(4,451)
$ (100,797) $ 271,415
Net cash provided by (used in) operating activities of
continuing operations
Add: proceeds from sale of PP&E
Add: proceeds from sale of mineral rights
Add: return on long-term contract receivables—
affiliate
Less: maintenance capital expenditures
Less: distributions to non-controlling interest
Distributable Cash Flow
$ 204,934
$
43,029
$
23,605
10,100
3,505
2,463
(416)
(2,744)
$ 217,842
—
—
—
—
—
924
—
—
(5,727)
—
$
43,029
$
18,802
$ (103,056) $ 168,512
11,024
—
—
3,505
—
—
2,463
(6,143)
(2,744)
$ (103,056) $ 176,617
—
DCF increased $94.8 million, or 54%, from $176.6 million in the year ended December 31, 2015 to $271.4 million in the
year ended December 31, 2016. This increase is due primarily to the $109.9 million net cash proceeds from the sale of our
discontinued operation in addition to $61.0 million in net cash proceeds from sales of mineral rights in 2016. These increases were
partially offset by lower coal royalty production, lower coal royalty revenue per ton and less minimum payments received from
our coal leases. These decreases are driven by the continued pressure on U.S. coal producers as described above. See "Item 6.
Selected Financial Data—Non-GAAP Financial Measures—Distributable Cash Flow" for an explanation of Distributable Cash
Flow.
53
Results of Operations
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Revenues and Other Income
Revenues and other income increased $88.7 million, or 25%, from $350.9 million in the year ended December 31, 2014 to
$439.6 million in the year ended December 31, 2015. The following table shows our diversified sources of natural resource revenues
and other income by business segment for the years ended December 31, 2015 and 2014 (in thousands except for percentages):
2015
Revenues
Percentage of total
2014
Revenues
Percentage of total
Coal Royalty and
Other
Soda Ash
VantaCore
Total
250,717
49,918
139,013
439,648
57%
11%
32%
267,451
76%
41,416
12%
42,051
12%
350,918
The changes in revenue and other income is discussed for each of the our business segments below:
Coal Royalty and Other
Revenues and other income related to our Coal Royalty and Other segment decreased $16.8 million, or 6%, from $267.5
million in 2014 to $250.7 million in 2015.
54
The table below presents coal royalty production and revenues derived from our major coal producing regions and the
significant categories of other coal royalty and other revenues:
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
Coal royalty revenues
Appalachia
Northern
Central
Southern
Total Appalachia
Illinois Basin
Northern Powder River Basin
Gulf Coast
Total coal royalty revenue
Other revenues
Coal override revenue
Transportation and processing fees
Minimums recognized as revenue
Lease assignment fee
Gain on reserve swap
Wheelage
Hard mineral royalty revenues
Oil and gas royalty revenues
Property tax revenue
Other
Total other revenues
Coal royalty and other income
Gain on coal royalty and other segment asset sales
Total coal royalty and other segment revenues and other income
For the Years Ended
December 31,
2015
2014
Increase
(Decrease)
Percentage
Change
(In thousands, except percent and per ton data)
(Unaudited)
9,562
16,862
3,803
30,227
11,173
4,905
740
47,045
0.28
3.85
4.57
3.94
2.54
3.47
2,672
64,877
17,390
84,939
44,063
12,443
2,570
144,015
2,920
22,033
15,489
21,000
9,290
3,166
8,090
4,364
11,258
2,156
99,766
243,781
6,936
250,717
$
$
$
$
$
$
9,339
20,092
3,914
33,345
13,177
2,844
1,093
50,459
0.92
4.46
5.18
4.10
2.74
3.47
8,621
89,627
20,292
118,540
54,049
7,804
3,793
184,186
4,601
22,048
6,659
—
5,690
3,442
12,073
10,732
13,609
3,045
81,899
266,085
1,366
267,451
$
$
$
$
$
$
$
$
$
$
$
$
223
(3,230)
(111)
(3,118)
(2,004)
2,061
(353)
(3,414)
(0.64)
(0.61)
(0.61)
(0.16)
(0.20)
—
(5,949)
(24,750)
(2,902)
(33,601)
(9,986)
4,639
(1,223)
(40,171)
(1,681)
(15)
8,830
21,000
3,600
(276)
(3,983)
(6,368)
(2,351)
(889)
17,867
(22,304)
5,570
(16,734)
2 %
(16)%
(3)%
(9)%
(15)%
72 %
(32)%
(7)%
(70)%
(14)%
(12)%
(4)%
(7)%
— %
(69)%
(28)%
(14)%
(28)%
(18)%
59 %
(32)%
(22)%
(37)%
— %
133 %
100 %
63 %
(8)%
(33)%
(59)%
(17)%
(29)%
22 %
(8)%
408 %
(6)%
Total coal production decreased 3.4 million tons, or 7%, from 50.4 million tons in 2014 to 47.0 million tons in 2015. Total
coal royalty revenues decreased $40.2 million, or 22%, from $184.2 million in 2014 to $144.0 million in 2015. During 2015,
depressed coal prices negatively affected our coal related revenues. During the year ended December 31, 2015 as compared to
2014, total coal production and total coal royalty revenues were down in Appalachia, the Illinois Basin and the Gulf Coast, while
we saw a significant increase in the Northern Powder River Basin. All Appalachian regions saw a decrease in coal royalty revenues
during the year with coal royalty revenues in Northern Appalachia down 69% despite a 2% increase in production from that area.
We saw a decrease in the average coal revenue per ton throughout all of our regions, with the exception of the Gulf Coast whose
average coal revenue per ton remained flat, for the year ended December 31, 2015 when compared to the year ended December
31, 2014.
55
Other coal royalty and other income increased $17.9 million, or 22%, from $81.9 million in 2014 to $99.8 million in 2015.
This increase is primarily a result of two lease assignment fee payments received in 2015 totaling $21.0 million, an $8.8 million
increase in minimums recognized as revenue and a $3.6 million increase in reserve swap gains year-over-year. These increases
were partially offset by decreased oil and gas royalty revenue as a result of lower commodity prices year-over-year and decreases
in hard mineral royalty revenues, property taxes and override revenue in 2015 when compared to 2014.
Soda Ash
Revenues and other income related to our Soda Ash segment increased $8.5 million, or 21%, from $41.4 million in 2014 to
$49.9 million in 2015. This increase is primarily related to our allocated percentage of Ciner Wyoming's $15.0 million increase
in income year-over-year. For the year ended December 31, 2015, we received $46.8 million in cash distributions from Ciner
Wyoming and for the year ended December 31, 2014, we received $46.6 million in cash distributions.
VantaCore
Tonnage sold by the VantaCore segment increased 5.1 million tons from 2.3 million tons in 2014 to 7.4 million tons in 2015.
Revenues and other income related to our VantaCore segment increased $96.9 million, or 231%, from $42.1 million in 2014 to
$139.0 million in 2015. This increase is due to the fact that VantaCore was acquired in the fourth quarter of 2014.
Operating and Maintenance Expenses (including affiliates)
Operating and maintenance expenses (including affiliates) increased $76.2 million, or 100%, from $76.1 million in 2014 to
$152.3 million in 2015. This increase is primarily related to the following:
VantaCore
Operating and maintenance expenses in our VantaCore segment increased $78.2 million from $38.7 million in 2014 to $116.9
million in 2015. This increase is due to the fact that 2014 results only include three months of VantaCore activity as compared to
twelve months in 2015.
Depreciation, Depletion and Amortization ("DD&A") Expense
DD&A expense decreased $1.0 million from $61.9 million in 2014 to $60.9 million in 2015. This decrease is primarily
related to the following:
Coal Royalty and Other
DD&A expense for our Coal Royalty and Other segment decreased $13.3 million, or 23%, from $58.6 million in 2014 to
$45.3 million in 2015. This decrease was primarily the result of the reduction in depletion expense on the assets that were impaired
during the third and fourth quarters of 2015 and reduced production year-over-year.
VantaCore
DD&A expense for our VantaCore segment increased $12.3 million from $3.3 million in 2014 to $15.6 million in 2015. This
increase was due to the fact that 2014 results only include three months of activity as compared to a full year in 2015.
General and Administrative (including affiliates) ("G&A") Expense
Corporate and financing G&A expense includes corporate headquarters, financing and centralized treasury and accounting.
These costs increased $1.8 million, or 17%, from $10.5 million in 2014 to $12.3 million in 2015. This increase was primarily due
to an increase in salaries, bonus and benefits, consulting, rent and legal fees. This increase was partially offset by a decrease in
LTIP expense as a result of the decline in unit price year-over-year.
56
Asset Impairment
Asset impairment expense increased $358.3 million from $26.2 million in 2014 to $384.5 million in 2015. We recorded the
following asset impairments during the years ended December 31, 2015 and 2014 (in thousands):
Impaired Assets
Coal Royalty and Other
Mineral Rights
Plant and Equipment
Intangible Assets
Total Coal Royalty and Other Impairment
VantaCore
Plant and Equipment
Goodwill
Total VantaCore Impairment
Total impairment
Coal Royalty and Other
For the Year Ended
December 31,
2015
2014
$
$
$
$
$
371,397
6,930
—
378,327
692
5,526
6,218
384,545
$
$
$
$
$
19,806
779
5,624
26,209
—
—
—
26,209
Asset impairment expense related to our Coal Royalty and Other segment increased $352.1 million from $26.2 million in
2014 to $378.3 million in 2015. This increase was primarily due to the significant impairment expense taken in the third quarter
2015. Coal property impairments primarily resulted from idled operations in Appalachia combined with the continued deterioration
in the coal markets and expectations of further reductions in global and domestic coal demand due to reduced global steel demand,
low natural gas prices, and continued regulatory pressure on the electric power generation industry. Oil and gas royalty property
impairments primarily results from declines in future expected realized commodity prices and reduced expected drilling activity
on our acreage. Aggregate royalty property impairments primarily resulted from greenfield development projects that have not
performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional
market decline for certain properties. During the fourth quarter of 2015, we recognized an additional $8.2 million impairment
expense on our coal properties as a result of continued market declines and $4.7 million impairment expense related to coal
processing and transportation assets as well as obsolete equipment at our Logan office. During the second quarter of 2015 we
recorded a $2.3 million impairment expense related to a coal preparation plant.
VantaCore
The $6.2 million impairment expense in 2015 was related to a $5.5 million write off of goodwill as well as a $0.7 million
impairment related to obsolete plant and equipment.
Interest Expense
Interest expense increased $10.3 million, or 13%, from $79.4 million in 2014 to $89.7 million in 2015. This increase was
primarily the result of additional debt incurred to complete acquisitions in the fourth quarter of 2014.
Income (Loss) from Discontinued Operations
Income from discontinued operations decreased $323.6 million, from income of $12.1 million in 2014 to a loss of $311.5
million in 2015. The change in income (loss) from discontinued operations primarily related to asset impairments recorded in 2015
due to the declines in future expected realized commodity prices and reduced expected drilling activity and reduced oil and gas
prices in 2015 compared to 2014.
57
Adjusted EBITDA (Non-GAAP Financial Measure)
The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP
financial measure) to Adjusted EBITDA by business segment for the years ended December 31, 2015 and 2014:
For the Year Ended
December 31, 2015
Operating Segments
Coal Royalty
and Other
Soda Ash
VantaCore
Corporate
and
Financing
Total
Net income (loss) from continuing operations
Less: equity earnings from unconsolidated investment
Less: gain on reserve swap
Add: distributions from unconsolidated investment
Add: interest expense
Add: depreciation, depletion and amortization
Add: asset impairment
$ (208,248) $
—
(9,290)
—
—
45,338
378,327
49,918
(49,918)
—
46,795
—
—
—
$
251
—
—
—
15,578
6,218
Adjusted EBITDA
$ 206,127
$
46,795
$
22,047
—
$ (102,092) $ (260,171)
(49,918)
(9,290)
46,795
89,762
60,916
384,545
$ (12,330) $ 262,639
—
89,762
—
—
December 31, 2014
Net income (loss) from continuing operations
$ 145,237
$
Less: equity earnings from unconsolidated investment
Less: gain on reserve swap
Add: distributions from unconsolidated investment
Add: interest expense
Add: depreciation, depletion and amortization
Add: asset impairment
Adjusted EBITDA
—
(5,690)
—
—
58,598
26,209
$
41,416
(41,416)
—
46,638
—
—
—
32
—
—
—
—
3,296
—
$ (89,972) $
—
—
—
79,523
—
96,713
(41,416)
(5,690)
46,638
79,523
61,894
—
26,209
$ (10,449) $ 263,871
$ 224,354
$
46,638
$
3,328
Adjusted EBITDA decreased $1.3 million from $263.9 million in 2014 to $262.6 million in 2015. The decrease is mainly
related to declines in our Coal Royalty and Other segment, partially offset by higher income from our VantaCore business that
was acquired in October 2014. Adjusted EBITDA is a non-GAAP financial measure. See "Item 6. Selected Financial Data—Non-
GAAP Financial Measures—Adjusted EBITDA" for an explanation of Adjusted EBITDA.
58
Distributable Cash Flow (Non-GAAP Financial Measure)
The following table (in thousands) presents the three major categories of the statement of cash flows by business segment
for the years ended December 31, 2015 and 2014:
Operating Segments
Coal Royalty
and Other
Soda Ash
VantaCore
Corporate
and
Financing
Total
$ 204,934
15,805
$
$
43,029
$
23,605
$ (103,056) $ 168,512
— $
(8,820) $
— $
6,985
(2,744) $
— $
— $ (180,520) $ (183,264)
For the Year Ended
December 31, 2015
Net cash provided by (used in) operating activities of
continuing operations
Net cash provided by (used in) investing activities of
continuing operations
Net cash provided by (used in) financing activities of
continuing operations
December 31, 2014
Net cash provided by (used in) operating activities of
continuing operations
$
$
$ 238,564
$
42,516
$
2,746
$ (91,662) $ 192,164
Net cash provided by (used in) investing activities of
continuing operations
Net cash provided by (used in) financing activities of
continuing operations
$
$
(2,067) $
3,633
$ (171,078) $
— $ (169,512)
(974) $
— $
— $ (65,012) $ (65,986)
59
The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial
measure) by business segment to DCF for the years ended December 31, 2015 and 2014:
For the Year Ended
December 31, 2015
Net cash provided by (used in) operating activities of
continuing operations
Add: proceeds from sale of PP&E
Add: proceeds from sale of mineral rights
Add: return on long-term contract receivables—
affiliate
Less: maintenance capital expenditures
Less: distributions to non-controlling interest
Distributable Cash Flow
December 31, 2014
Operating Segments
Coal Royalty
and Other
Soda Ash
VantaCore
Corporate
and
Financing
Total
$ 204,934
10,100
3,505
2,463
(416)
(2,744)
$ 217,842
$
$
43,029
—
—
—
—
—
43,029
$
$
23,605
924
—
$ (103,056) $ 168,512
11,024
3,505
—
—
—
(5,727)
—
18,802
—
—
—
2,463
(6,143)
(2,744)
$ (103,056) $ 176,617
Net cash provided by (used in) operating activities of
continuing operations
$ 238,564
$
42,516
$
2,746
Add: return of unconsolidated equity investment
Add: proceeds from sale of PP&E
Add: proceeds from sale of mineral rights
Add: return on long-term contract receivables—
affiliate
Less: maintenance capital expenditures
Less: distributions to non-controlling interest
Distributable Cash Flow
—
968
412
1,904
(316)
(974)
$ 240,558
3,633
—
—
—
—
—
—
38
—
—
(900)
—
$
46,149
$
1,884
$ (91,662) $ 192,164
3,633
—
—
—
1,006
412
—
—
1,904
(1,216)
(974)
$ (91,662) $ 196,929
—
Distributable Cash Flow for 2015 decreased $20.3 million, or 10%, from $196.9 million in 2014 to $176.6 million in 2015.
This decrease is due primarily to a reduction in cash provided by our coal operations, partially offset by our VantaCore business
that was acquired in October 2014. Distributable Cash Flow is a non-GAAP financial measure. See "Item 6. Selected Financial
Data—Non-GAAP Financial Measures—Distributable Cash Flow" for an explanation of Distributable Cash Flow.
60
Liquidity and Capital Resources
2017 Restructuring Transactions
The following discussion describes the recapitalization transactions completed on March 2, 2017 and the terms of the preferred
units, warrants to purchase common units and debt securities issued in connection therewith.
Issuance of Preferred Units and Warrants
We issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred
Units") to Blackstone and GoldenTree (together the "Preferred Purchasers") pursuant to a Preferred Unit and Warrant Purchase
Agreement. We 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 dividends 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"). We 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, we may, at our option, elect to settle the Warrants in common
units or cash, each on a net basis.
The Preferred Units have a perpetual term, unless converted or redeemed as described below. The Preferred Units (including
any PIK Units) are convertible into common units at the election of the holders (1) after the fifth anniversary and prior to the eighth
anniversary of the issue date at a 7.5% discount to the volume weighted average trading price of our common units (the "VWAP")
for the 30 trading days immediately prior to the notice of conversion if the 30-day VWAP immediately prior to such notice is
greater than $51.00 (subject to a maximum of 33% of the Preferred Units per year) and (2) after the eighth anniversary of the issue
date at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Instead of issuing
common units pursuant to clause (1) of the preceding sentence, we have the option to redeem the Preferred Units proposed to be
converted for cash at a price equal to the Per Unit Purchase Price, plus the value of any accrued and unpaid distributions. To the
extent the holders of the Preferred Units have not elected to convert their Preferred Units by the twelfth anniversary of the issue
date, we have the right to force conversion of the Preferred Units into common units at a 10% discount to the VWAP for the 30
trading days immediately prior to the notice of conversion. In addition, we have the ability to redeem at any time (subject to
compliance with our debt agreements) all or any portion of the Preferred Units (including PIK Units) for cash at the agreed upon
per unit amount, which is calculated as the Per Unit Purchase Price multiplied by (i) prior to the third anniversary of the closing
date, 1.50, (ii) on or after the third anniversary of the closing date and prior to the fourth anniversary of the closing date, 1.70 and
(iii) on or after the fourth anniversary of the closing date, 1.85.
The terms of the Preferred Units contain certain restrictions on our ability to pay distributions on our common units. To the
extent that either (i) our consolidated Leverage Ratio (as defined in the Restated Partnership Agreement) is greater than 3.25x, or
(ii) the ratio of our Distributable Cash Flow to cash distributions made or proposed to be made is less than 1.2x (in each case, with
respect to the most recently completed four-quarter period), we may not increase the quarterly distribution above $0.45 per quarter
without the approval of the holders of a majority of the outstanding Preferred Units. In addition, if at any time after January 1,
2022, any PIK Units are outstanding, we may not make distributions on our common units until we have redeemed all PIK Units
for cash.
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, including:
•
the incurrence of new indebtedness, subject to certain exceptions;
• material changes to NRP’s business;
•
•
•
acquisitions and divestitures in excess of certain dollar thresholds;
amendments to material contracts resulting in a cash impact to NRP in excess of certain dollar thresholds;
settlement of any litigation or regulatory matter resulting in cash payments by NRP in excess of certain thresholds;
and
61
•
amendments to related party contracts outside of the ordinary course of business.
GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the Minimum
Preferred Unit Threshold (as defined below). The Preferred Purchaser Approval Rights are not transferrable without our consent.
In addition, the Preferred Purchaser 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"). To the extent any Preferred Units that have converted into common units are still held by
the applicable Preferred Purchaser (or its affiliates), such common units will be deemed to represent a number of Preferred Units
based on the weighted average number of common units issued in each conversion and will count towards the Minimum Preferred
Unit Threshold.
The foregoing terms of the Preferred Units are reflected in our Fifth Amended and Restated Agreement of Limited Partnership,
dated as of March 2, 2017, which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference.
The terms of the Warrants are reflected in the Form of Warrant to Purchase Common Units filed as Exhibit 4.28 to this Annual
Report on Form 10-K, which is incorporated herein by reference.
At the closing, pursuant to a Board Representation and Observation Rights Agreement, the Preferred Purchasers received
certain board appointment and observation rights and appointed one director and one observer to the Board of Directors of GP
Natural Resource Partners LLC. For more information on these rights, see "Certain Relationships and Related Transactions, and
Director Independence—Board Representation and Observation Rights Agreement."
We also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with
the Preferred Purchasers, pursuant to which we are 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. If the shelf registration statements are not effective by the
applicable Registration Deadline, we 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.
Opco Credit Facility Amendment
We entered into the Second Amendment to Opco’s Third Amended and Restated Credit Agreement to extend the term thereof
until April 2020, and reduced the commitments of the lenders to $180 million (from $210 million) effective at the closing of the
recapitalization transactions. Pursuant the Second Amendment, commitments under the Opco Credit Facility will be reduced to
$150 million at December 31, 2017 and further reduced to $100 million at December 31, 2018 through maturity in April 2020.
The amendment does not change the pricing grid or financial covenants under the Opco Credit Facility; provided, however, that
if we increase our quarterly distribution to our 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. Other terms of the Second Amendment include
revisions to the mandatory prepayment provisions with respect to net cash proceeds received from certain asset sales, additional
limitations on the ability of Opco and its subsidiaries to make certain investments. The Second Amendment is filed as Exhibit
10.14 to this Annual Report on Form 10-K and is incorporated herein by reference.
Issuance of 2022 Notes; Exchange and Redemption of 2018 Notes
NRP and NRP Finance issued $346 million aggregate principal amount of 10.500% Senior Notes due 2022 to several holders
of its 2018 Notes. Of the $346 million of 2022 Notes issued, $241 million in aggregate principal amount were issued in exchange
for $241 million in aggregate principal amount of 2018 Notes, and $105 million of the 2022 Notes were issued to the holders in
exchange for cash. The 2022 Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 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.
62
We and NRP Finance have the option to redeem the 2022 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, we may on any one or more occasions
redeem up to 35% of the aggregate principal amount of the 2022 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 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 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 Notes may require
us to purchase their 2022 Notes at a purchase price equal to 101% of the principal amount of the 2022 Notes, plus accrued and
unpaid interest, if any. The 2022 Notes purchased for cash were issued at a price of 98.75% (original issue discount of 1.25%),
and each holder exchanging 2018 Notes received a fee of 5.813% of the aggregate principal amount of all 2018 Notes tendered
for exchange by such holder, as well as all accrued and unpaid interest thereon.
The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing
the 2018 Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under the debt
incurrence covenant, our 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 our 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 we have made the election described in clause (i) above). Under the restricted
payments covenant, we will not be able to increase the quarterly distribution on our common units or elect to pay more than 50%
of the distributions required to be made on the Preferred Units in the form of cash, unless, in each case, our consolidated leverage
ratio is less than 4.00x. The 2022 Indenture also contains restrictions on our ability to redeem the Preferred Units in cash.
The 2022 Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Notes rank equal in right of
payment to all existing and future senior unsecured debt of NRP and NRP Finance, including the remaining outstanding 2018
Notes, and senior in right of payment to any of our subordinated debt. The 2022 Notes are effectively subordinated in right of
payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness
and are structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including
the Opco Credit Facility and each series of Opco’s existing senior notes. None of our subsidiaries guarantee the 2022 Notes.
The terms of the 2022 Notes are more fully described in the 2022 Indenture, which is filed as Exhibit 4.24 to this Annual
Report on Form 10-K and incorporated herein by reference.
We entered into a registration rights agreement (the "Notes Registration Rights Agreement") with the holders of the 2022
Notes, pursuant to which we and NRP Finance agreed to file a registration statement with the Securities and Exchange Commission
for the benefit of the holders of the 2022 Notes so that such holders can exchange the 2022 Notes for exchange securities that have
substantially identical terms as the 2022 Notes. We and NRP Finance agreed to use commercially reasonable efforts to cause the
exchange to be completed within 180 days after the closing and will be required to pay additional interest, as specified in the Notes
Registration Rights Agreement, if we fail to comply with our obligations to register the 2022 Notes within the specified time
periods.
We expect to redeem $90 million in aggregate principal amount of the 2018 Notes at a redemption price of 104.563%, and
pay all accrued and unpaid interest thereon, in April 2017. In addition, we are required to redeem any and all remaining outstanding
2018 Notes (and pay all accrued and unpaid interest thereon) within 60 days after October 1, 2017.
63
The following table summarizes our long-term debt and convertible preferred unit obligations at December 31, 2016 and at
December 31, 2016 after giving pro forma effect to the recapitalization transactions described above (in millions):
As of December 31, 2016
2017
2018 Notes
Opco Credit Facility
Opco Senior Notes and other
Total long-term debt obligations
$
$
— $
60.0
80.6
140.6
$
2018
425.0
150.0
80.6
655.6
$
$
2019
2020
2021
Thereafter
Total
— $
—
76.0
76.0
$
— $
—
54.7
54.7
$
— $
—
47.0
47.0
$
— $
—
164.9
164.9
425.0
210.0
503.8
$ 1,138.8
Payments Due by Period
After Recapitalization Transactions
2017
2018
2019
2020
2021
Payments Due by Period
2022 Notes
2018 Notes
Opco Credit Facility(1)
Opco Senior Notes and other
Total long-term debt obligations
Convertible preferred unit obligations
Total long-term debt and convertible
preferred unit obligations
$
— $
94.0
—
80.6
— $
—
—
80.6
— $
—
—
76.0
— $
—
—
54.7
Thereafter
346.0
—
—
164.9
— $
—
—
47.0
$
$
174.6
$
80.6
$
76.0
$
54.7
$
47.0
$
510.9
— $
— $
— $
— $
— $
250.0
Total
346.0
94.0
—
503.8
943.8
250.0
$
$
$
$
174.6
$
80.6
$
76.0
$
54.7
$
47.0
$
760.9
$ 1,193.8
(1) Assumes no additional borrowings under the Opco Credit Facility following closing.
Current Liquidity
Generally, we satisfy our working capital requirements with cash generated from operations. Our current liabilities exceeded
our current assets by approximately $83.8 million as of December 31, 2016, primarily due to $80.6 million in total principal
payments due in 2017 on the Opco Senior Notes and Opco utility local improvement obligation and $60.0 million of payments
due in 2017 on the Opco Credit Facility. Excluding these principal payments, our current assets exceeded our current liabilities
by approximately $56.8 million as of December 31, 2016. In March 2017, we increased our liquidity through the completion of
the recapitalization transactions described above. In addition to enhancing our liquidity, these recapitalization transactions reduced
our 2018 debt maturities by $575 million through the extension of debt principal payments from 2018 to 2020 and 2022.
Capital Expenditures
A portion of the capital expenditures associated with our VantaCore segment are maintenance capital expenditures, which
are capital expenditures made to maintain the long-term production capacity of those businesses. Expansion capital expenditures
are made to increase productive capacity. We deduct maintenance capital expenditures when calculating DCF. VantaCore’s
maintenance and expansion capital expenditures for the year ended December 31, 2016 were $4.4 million and $1.0 million,
respectively.
Cash Flows
Cash flow provided by operating activities decreased $95.4 million, from $203.4 million in the year ended December 31,
2015 to $108.0 million in the year ended December 31, 2016. Operating cash flow from continuing operations decreased $70.4
million in our Coal Royalty and Other segment year-over-year primarily as a result of the reduction in coal royalty revenue and
reduction of coal royalty minimum cash payments received on certain leases. Cash flow provided by operating activities of
discontinued operations decreased $27.6 million, from $34.9 million in the year ended December 31, 2015 to $7.3 million in the
year ended December 31, 2016 primarily as a result of completing the sale of our non-operated oil and gas working interest assets
in July 2016 that had an effective date of April 1, 2016.
64
Cash flow provided by operating activities decreased $7.4 million, from $210.8 million in the year ended December 31,
2014 to $203.4 million in the year ended December 31, 2015. Operating cash flow from continuing operations decreased $33.7
million in our Coal Royalty and Other segment year-over-year primarily as a result of the reduction in coal royalty revenue and
reduction of coal royalty minimum cash payments received on certain leases. Corporate and Financing used an additional $11.4
million in operating activities of continuing operations primarily due to the increase in cash paid for interest year-over-year. These
decreases were partially offset by a $20.9 million increase in cash provided by operating activities of continuing operations in our
VantaCore segment primarily due to a full year of operations due to the fourth quarter of 2014 acquisition. Cash flow provided by
operating activities of discontinued operations increased $16.3 million, from $18.6 million in the year ended December 31, 2014
to $34.9 million in the year ended December 31, 2015 primarily as a result of a full year of revenue on our fourth quarter 2014
Williston Basin non-operated working interest asset acquisition.
Cash flow provided by investing activities increased $197.1 million, from $30.3 million used in the year ended December
31, 2015 to $166.8 million provided in the year ended December 31, 2016. Investing cash flows from discontinued operations
increased $144.2 million primarily as a result of the sale of our non-operated oil and gas working interest assets in July 2016 for
$109.9 million in net cash proceeds in addition to a $37.8 million decrease in cash flow used as a result of lower oil and gas drilling
activity and the non-operated working interest asset sale in July 2016. Investing cash flows from continuing operations increased
$52.9 million primarily as a result of 2016 sales of oil and gas and aggregate royalty properties.
Cash flow used by investing activities decreased $490.2 million, from $520.5 million in the year ended December 31, 2014
to $30.3 million in the year ended December 31, 2015 primarily due to the 2014 VantaCore acquisition and various 2015 asset
sales including an aggregate preparation plant, cell phone tower lease contracts and condemnation payments within our Coal
Royalty and Other segment, partially offset by plant and equipment acquisitions within our VantaCore segment. Cash flow used
by investing activities of discontinued operations decreased $313.7 million primarily due to our 2014 investing activities consisting
of our Sanish Field acquisition as well as additional capital expenditures related to the participation in new wells, partially offset
by 2015 well participation costs.
Cash flow used in financing activities increased $114.7 million, from $171.5 million in the year ended December 31, 2015
to $286.2 million in the year ended December 31, 2016. Cash used in financing activities of discontinued operations increased
$136.6 million primarily as a result of using $85.0 million to repay the RBL Credit Facility and contributing the $39.4 million of
discontinued asset sales proceeds that remained after repayment of the RBL Facility in full to continuing operations. This increase
in cash flow used in financing activities was partially offset by a $21.9 million decrease in cash flow used in financing activities
from continuing operations primarily a result of distributing $49.3 million less cash to partners and receiving the remaining net
proceeds from discontinuing operations after repayment as described above.
Cash flow used in financing activities increased $438.8 million, from $267.3 million provided in the year ended December
31, 2014 to $171.5 million used in the year ended December 31, 2015 primarily due to $518.4 million in loan proceeds and $127.2
million in general partner contributions received during the year ended December 31, 2014. This change was partially offset by
higher distributions to partners and loan repayments made during 2014. Cash flow provided by financing activities of discontinued
operations decreased $321.5 million, from $333.3 million in the year ended December 31, 2014 to $11.8 million provided in the
year ended December 31, 2015, primarily as a result of contributions from continuing operations to fund investing activities of
the discontinued operation in 2014.
Capital Resources and Obligations
Indebtedness
As of December 31, 2016 and 2015, we had the following indebtedness (in thousands):
Current portion of long-term debt, net
Long-term debt and debt—affiliate, net
Total debt and debt—affiliate, net
December 31, 2016
138,903
$
987,400
1,126,303
$
December 31, 2015
80,745
$
1,290,211
1,370,956
$
We were and continue to be in compliance with the terms of the financial covenants contained in Opco's debt agreements.
Adjusted EBITDA as defined in "Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA" differs
65
from the EBITDDA definitions contained in our debt agreements. For additional information regarding our debt and the agreements
governing our debt, including the covenants contained therein, see and "—2017 Recapitalization Transactions" above and "Item
8. Financial Statements and Supplementary Data—Note 11. Debt and Debt—Affiliate" 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, 2016 (in millions):
Contractual Obligations
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)
Rental leases (4)
Total
Total
2017
2018
2019
2020
2021
Thereafter
Payments Due by Period
$ 425.0
77.6
$
— $ 425.0
38.8
38.8
$
— $
—
— $
—
— $
—
—
—
713.8
114.8
5.2
$ 1,336.4
140.6
28.1
2.2
$ 209.7
230.6
23.1
1.6
$ 719.1
$
76.0
18.1
0.1
94.2
$
54.7
14.2
0.1
69.0
$
47.0
11.1
0.1
58.2
164.9
20.2
1.1
186.2
$
(1) The amounts indicated in the table include principal and interest due on NRP’s 2018 Notes.
(2) The amounts indicated in the table include principal due on Opco’s senior notes, credit facility and utility local improvement
obligation.
(3) The amounts indicated in the table include interest due on Opco’s senior notes and utility local improvement obligation.
(4) The rental lease amounts primarily consist of office space and VantaCore equipment leases.
Shelf Registration Statement
In September 2015, we filed a registration statement on Form S-3 with the SEC that is available for registered offerings of
common units.
Off-Balance Sheet Transactions
We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are
no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.
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, 2016, 2015 and 2014.
Environmental Regulation
For additional information on environmental regulation that may have a material impact on our business, see "Item 1.
Business and Properties—Regulation and Environmental Matters."
Related Party Transactions
The information required by this Item is included under "Item 8. Financial Statements and Supplementary Data—Note 13.
Related Party Transactions" and "Item 13. Certain Relationships and Related Transactions, and Director Independence" in this
Annual Report on Form 10-K and is incorporated by reference herein.
66
Summary of Critical Accounting Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in
the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying
Consolidated Statements of Comprehensive Income during the reporting period. See "Note 2. Summary of Significant Accounting
Policies" to the audited consolidated financial statements under Item 8 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.
Revenues
Coal Royalty and Other Revenues. Coal royalty and other revenues are recognized on the basis of tons of mineral sold by
our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a
percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons
of material processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees
of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per
ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees
are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and
processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms
of the transportation contracts, we receive a fixed price per ton for all material transported on the beltlines.
Most of our coal and aggregates lessees must make minimum annual or quarterly payments which are generally recoupable
over certain time periods. These minimum payments are recorded as a deferred revenue liability when received. The deferred
revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee
recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to
recoup the payments.
Oil and gas related revenues consist of revenues from royalties and overriding royalties. Oil and gas royalty revenues are
recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales.
Equity in Earnings from Ciner Wyoming. We account for non-marketable equity investments using the equity method of
accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee. Significant
influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee.
We account for our investment in Ciner Wyoming 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 the investee's net assets is hypothetically allocated first to identified tangible assets and liabilities, then
to finite-lived intangibles or indefinite-lived intangibles and the remaining balance is attributed to goodwill. The portion of the
basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while
indefinite-lived intangibles, if any, and goodwill are not amortized. The amortization of the basis difference is recorded as a
reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income.
Our carrying value in an equity method investee company is reflected in the caption "Equity and other unconsolidated
investments" in our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of the investee company is reflected
in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity and other
unconsolidated investment income." Our share of investee earnings are adjusted to reflect the amortization of any difference
between the cost basis of the equity investment and the proportionate share of the investee’s net assets, which has been allocated
to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets.
VantaCore Revenues. Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer
of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction
contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to
the estimated total costs for each contract. That method is used since we consider total cost to be the best available measure of
progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses
67
are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract
settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined.
Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies,
insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred.
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 aggregate 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 periodically evaluate our long-lived assets for possible impairment. These procedures are
performed throughout the year and are based on historic, current and future performance and are designed to be early warning
tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative
and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use
and disposition 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. In addition to the evaluations
discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for
an extended period may require a separate impairment evaluation be completed on a significant property.
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" to 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
We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various
long-term and short-term contracts as well as on the spot market. Current conditions in the coal industry may make it difficult for
our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees’ failure to negotiate
long-term contracts could adversely affect the stability and profitability of our lessees’ operations and adversely affect our coal
royalty revenues. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in
spot coal prices.
68
We have market risk related to prices for our aggregates products. Aggregates prices are primarily driven by economic
conditions in the local markets in which the products are sold.
The market price of soda ash directly affects the profitability of Ciner Wyoming’s operations. If the market price for soda
ash declines, Ciner Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for
soda ash have been volatile, and those markets are likely to remain volatile in the future.
Interest Rate Risk
Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to
variable interest rates based upon LIBOR. At December 31, 2016, we had $210.0 million outstanding in variable interest rate debt.
If interest rates were to increase by 1%, annual interest expense would increase approximately $2.1 million, assuming the same
principal amount remained outstanding during the year.
69
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, 2016 and 2015
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014
Consolidated Statements of Partners’ Capital for the years ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
Page
71
72
73
74
75
76
78
70
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Natural Resource Partners L.P.
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2016 and
2015, and the related consolidated statements of comprehensive income (loss), partners’ capital and cash flows for each of the
three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership's
management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the
financial statements of Ciner Wyoming LLC (Ciner Wyoming), a Limited Liability Company in which Natural Resource Partners
L.P. owns a 49% interest. In the consolidated financial statements Natural Resource Partners L.P.’s investment in Ciner Wyoming
is stated at $256 million and $262 million as of December 31, 2016 and 2015 respectively, and Natural Resource Partners L.P.’s
equity in the net income of Ciner Wyoming is stated at $40 million, $50 million, and $41 million for each of the three years in the
period ended December 31, 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 LLC, is based on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the
other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2016 and 2015, and the
consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in
conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
Natural Resource Partners L.P.'s internal control over financial reporting as of December 31, 2016, 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 6, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
March 6, 2017
71
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
We have audited the accompanying balance sheets of Ciner Wyoming LLC (the "Company") as of December 31, 2016 and
2015 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, 2016. These financial statements are the responsibility of the Company’s management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States) 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial
reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures
that are appropriate in the circumstances, 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. An audit also includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of
December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
March 6, 2017
72
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable, net
Accounts receivable—affiliates, net
Inventory
Prepaid expenses and other
Current assets of discontinued operations (see Note 3)
Total current assets
Land
Plant and equipment, net
Mineral rights, net
Intangible assets, net
Intangible assets, net—affiliate
Equity in unconsolidated investment
Long-term contracts receivable—affiliate
Other assets
Other assets—affiliate
Non-current assets of discontinued operations (see Note 3)
Total assets
Current liabilities:
LIABILITIES AND CAPITAL
Accounts payable
Accounts payable—affiliates
Accrued liabilities
Accrued liabilities—affiliates
Current portion of long-term debt, net
Current liabilities of discontinued operations (see Note 3)
Total current liabilities
Deferred revenue
Deferred revenue—affiliates
Long-term debt, net
Long-term debt, net—affiliate
Other non-current liabilities
Non-current liabilities of discontinued operations (see Note 3)
Commitments and contingencies (see Note 14)
Partners’ capital:
Common unitholders’ interest (12,232,006 units outstanding)
General partner’s interest
Accumulated other comprehensive loss
Total partners’ capital
Non-controlling interest
Total capital
Total liabilities and capital
December 31,
2016
2015
$
$
$
40,371
43,202
6,658
6,893
6,137
991
104,252
25,252
49,443
908,192
3,236
49,811
255,901
43,785
3,791
1,018
—
1,444,681
6,234
940
41,587
—
138,903
353
188,017
44,931
71,632
987,400
—
4,565
—
41,204
43,633
6,345
7,835
4,268
17,844
121,129
25,022
60,675
984,522
3,930
52,997
261,942
47,359
1,173
1,124
110,162
1,670,035
5,022
801
44,997
456
80,745
4,388
136,409
80,812
82,853
1,186,681
19,930
5,171
85,237
152,309
887
(1,666)
151,530
(3,394)
148,136
1,444,681
$
79,094
(606)
(2,152)
76,336
(3,394)
72,942
1,670,035
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
73
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands, except per unit data)
Revenues and other income:
Coal royalty and other
Coal royalty and other—affiliates
VantaCore
Equity in earnings of Ciner Wyoming
Gain on asset sales, net
Total revenues and other income
Operating expenses:
Operating and maintenance expenses
Operating and maintenance expenses—affiliates, net
Depreciation, depletion and amortization
Amortization expense—affiliate
General and administrative
General and administrative—affiliates
Asset impairments
Total operating expenses
Income (loss) from operations
Other income (expense)
Interest expense
Interest expense—affiliate
Interest income
Other expense, net
Net income (loss) from continuing operations
Income (loss) from discontinued operations (see Note 3)
Net income (loss)
Net income (loss) attributable to limited partners:
Continuing operations
Discontinued operations
Total
Net income (loss) attributable to the general partner:
Continuing operations
Discontinued operations
Total
Basic and diluted net income (loss) per common unit:
Continuing operations
Discontinued operations
Total
Average number of common units outstanding
Net income (loss)
Add: comprehensive income (loss) from unconsolidated investment
and other
Comprehensive income (loss)
For the Years Ended December 31,
2016
2015
2014
$
144,520
65,595
120,802
40,061
29,081
400,059
119,621
10,925
43,087
3,185
16,979
3,591
16,926
214,314
$
154,066
89,715
139,049
49,918
6,900
439,648
136,943
15,323
57,295
3,621
7,036
5,312
384,545
610,075
181,526
84,559
42,031
41,416
1,386
350,918
65,933
10,197
58,586
3,308
7,287
3,258
26,209
174,778
185,745
(170,427)
176,140
(90,047)
(523)
39
(90,531)
95,214
1,678
96,892
93,585
1,644
95,229
1,629
34
1,663
7.65
0.13
7.78
$
$
$
$
$
$
$
(87,911)
(1,851)
18
(89,744)
(260,171)
(311,549)
(571,720) $
(79,144)
(379)
96
(79,427)
96,713
12,117
108,830
(254,173) $
(305,319)
(559,492) $
94,779
11,874
106,653
(5,998) $
(6,230)
(12,228) $
(20.78) $
(24.97)
(45.75) $
1,934
243
2,177
8.37
1.05
9.42
12,232
12,232
11,326
96,892
$
(571,720) $
108,830
486
97,378
$
(1,693)
(573,413) $
(81)
108,749
$
$
$
$
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
74
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Common Unitholders
Units
Amounts
General
Partner
Accumulated
Other
Comprehensive
Income (Loss)
Partners'
Capital
Excluding
Non-
Controlling
Interest
Non-
Controlling
Interest
Total
Capital
Balance at December 31, 2013
10,983
$ 606,774
$
10,069
$
(378) $ 616,465
$
324
$ 616,789
Net income
Issuance of common units
Issuance of common units for
acquisitions
Capital contribution
Cost associated with equity
transactions
Distributions to unitholders
Distributions to non-
controlling interests
Comprehensive loss from
unconsolidated investment and
other
Balance at December 31, 2014
Net loss
Cost associated with equity
transactions
Distributions to unitholders
Distributions to non-
controlling interests
Non-cash contributions
Comprehensive loss from
unconsolidated investment and
other
—
1,006
106,653
127,202
243
31,604
2,177
—
—
—
—
—
—
—
—
3,240
(4,413)
—
(158,801)
(3,241)
—
—
—
—
—
—
—
—
—
—
—
108,830
127,202
31,604
3,240
(4,413)
(162,042)
—
—
—
—
—
—
108,830
127,202
31,604
3,240
(4,413)
(162,042)
—
(974)
(974)
(81)
(81)
—
(81)
12,232
—
$ 709,019
(559,492)
$
$
12,245
(12,228)
(459) $ 720,805
(571,720)
—
$
(650) $ 720,155
(571,720)
—
—
—
—
—
—
(109)
—
(70,324)
(1,434)
—
—
—
—
811
—
—
—
—
—
(109)
(71,758)
—
811
(1,693)
(1,693)
—
—
(109)
(71,758)
(2,744)
(2,744)
—
—
811
(1,693)
Balance at December 31, 2015
12,232
$
79,094
$
(606) $
(2,152) $
76,336
$
(3,394) $
72,942
Net income
Distributions to unitholders
Non-cash contributions
Comprehensive income from
unconsolidated investment and
other
—
—
—
—
95,229
(22,014)
—
—
1,663
(451)
281
—
—
—
96,892
(22,465)
281
—
486
486
—
—
—
—
96,892
(22,465)
281
486
Balance at December 30, 2016
12,232
$ 152,309
$
887
$
(1,666) $ 151,530
$
(3,394) $ 148,136
The accompanying notes are an integral part of these consolidated financial statements.
75
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income to net cash provided by operating
activities of continuing operations:
Depreciation, depletion and amortization
Amortization expense—affiliates
Distributions from equity earnings from unconsolidated investment
Equity earnings from unconsolidated investment
Gain on asset sales, net
(Income) loss from discontinued operations
Asset impairments
Gain on reserve swap
Other, net
Other, net—affiliates
Change in operating assets and liabilities:
Accounts receivable
Accounts receivable—affiliates
Accounts payable
Accounts payable—affiliates
Accrued liabilities
Accrued liabilities—affiliates
Deferred revenue
Deferred revenue—affiliates
Other items, net
Other items, net—affiliates
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:
Proceeds from sale of oil and gas royalty properties
Proceeds from sale of coal and aggregate royalty properties
Return of long-term contract receivables—affiliate
Proceeds from sale of plant and equipment and other
Acquisition of plant and equipment and other
Acquisition of mineral rights
Acquisition of aggregates business
Return of equity from unconsolidated investment
Net cash provided by (used in) investing activities of continuing
operations
Net cash provided by (used in) investing activities of discontinued
operations
Net cash provided by (used in) investing activities
For the Years Ended December 31,
2016
2015
2014
$
96,892
$
(571,720) $
108,830
43,087
3,185
46,550
(40,061)
(29,081)
(1,678)
16,926
—
8,284
993
431
(313)
707
139
4,618
(456)
(35,881)
(11,222)
(2,477)
—
100,643
7,318
107,961
42,844
18,189
2,968
1,350
(5,408)
—
—
—
59,943
106,872
166,815
57,295
3,621
46,795
(49,918)
(6,900)
311,549
384,545
(9,290)
(7,109)
(912)
7,705
3,149
(3,625)
(32)
1,420
—
7,605
(4,200)
(1,466)
—
168,512
34,912
203,424
—
3,505
2,463
11,024
(9,607)
(400)
—
—
58,586
3,308
43,005
(41,416)
(1,386)
(12,117)
26,209
(5,690)
(5,279)
(180)
4,483
(1,828)
(8,928)
457
6,002
456
2,056
15,618
(22)
—
192,164
18,591
210,755
—
412
1,904
1,006
(2,454)
(5,035)
(168,978)
3,633
6,985
(169,512)
(37,256)
(30,271)
(350,991)
(520,503)
Cash flows from financing activities:
Proceeds from loans
Proceeds from loan—affiliate
Proceeds from issuance of common units
Capital contribution by general partner
Repayments of loans
20,000
—
—
—
(183,141)
100,000
—
—
—
(165,983)
498,471
19,904
127,202
3,240
(318,983)
76
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Distributions to unitholders
Distributions to non-controlling interest
Contributions from (to) discontinued operations
Debt issue costs and other
Net cash used in financing activities of continuing operations
Net cash provided by (used in) financing activities of discontinued
operations
Net cash provided by (used in) financing activities
(22,465)
—
39,421
(15,234)
(161,419)
(124,759)
(286,178)
(71,758)
(2,744)
(36,725)
(6,054)
(183,264)
11,808
(171,456)
(162,042)
(974)
(226,000)
(6,804)
(65,986)
333,297
267,311
Net increase (decrease) in cash and cash equivalents
(11,402)
1,697
(42,437)
Cash and cash equivalents of continuing operations at beginning of period
Cash and cash equivalents of discontinued operations at beginning of period
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Less: cash and cash equivalents of discontinued operations at end of period
Cash and cash equivalents of continuing operations at end of period
Supplemental cash flow information:
Cash paid during the period for interest
Non-cash investing activities:
Plant, equipment and mineral rights funded with accounts payable or
accrued liabilities
Units issued for acquisition of aggregates business
$
$
$
$
41,204
10,569
51,773
40,371
—
40,371
$
48,971
1,105
50,076
51,773
10,569
41,204
$
92,305
208
92,513
50,076
1,105
48,971
84,380
$
85,738
$
75,833
— $
— $
4,304
$
— $
—
31,604
The accompanying notes are an integral part of these consolidated financial statements.
77
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,
operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona
and soda ash, construction aggregates and other natural resources and is organized into three operating segments further described
in Note 4. 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, a limited liability company
wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson
is entitled to nominate all ten of the directors to the board of directors of GP Natural Resource Partners LLC. Mr. Robertson has
delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, LLC, an affiliate of
Christopher Cline.
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 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
which is accounted for using the equity method. Intercompany transactions and balances have been eliminated.
Management’s Going Concern Analysis
While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive
operating cash flows, its operating results and credit metrics have been impacted by challenges in coal and other commodity
markets. The following going concern analysis includes discussion of the relevant conditions and events and an evaluation of
NRP's ability to meet its obligations and remain in compliance with its debt covenants within one year after the issuance date of
these financial statements.
In order to mitigate the effect of these adverse market developments on the Partnership's ability to remain in compliance
with the covenants under its debt agreements and meet scheduled debt principal payments, the Partnership pursued or considered
a number of actions. On a cumulative basis since January 1, 2015, the Partnership reduced debt by $339.1 million and completed
asset sales for $199 million in gross sales proceeds. In addition, the Partnership completed the following series of recapitalization
transactions on March 2, 2017 (see Note 19. Subsequent Events for further detail):
•
•
•
the issuance of $250 million of a new class of 12.0% preferred units representing limited partner interests in NRP,
together with warrants to purchase common 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");
the exchange of $241 million of our 9.125% Senior Notes due 2018 (the "2018 Notes") for $241 million of a new
series of 10.500% Senior Notes due 2022 (the "2022 Notes"), and the sale of $105 million of additional 2022 Notes
in exchange for cash proceeds; and
the extension of Opco’s revolving credit facility (the "Opco Credit Facility") to April 2020, with commitments
thereunder reduced to $180 million.
78
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
These recapitalization transactions increased the Partnership's liquidity and reduced the Partnership's 2018 debt maturities
by $575 million through the extension of debt principal payments from 2018 to 2020 and 2022. While the Partnership continues
to face challenges in coal and other commodity markets, it expects that it will meet all of its obligations, including scheduled
principal and interest payments on its debt and required distributions on the convertible preferred units, that it will remain in
compliance with its debt covenants and that it will continue as a going concern.
Recasting of Certain Prior Period Information
As described in Note 3. Discontinued Operations, the Partnership has classified the assets and liabilities, operating results
and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated financial
statements for all periods presented. As described in Note 4. Segment Information, the Partnership has reclassified oil and gas
royalty activities in prior period amounts to conform to the way it internally manages and monitors segment performance that had
no impact on the Partnership's consolidated financial position, net income (loss) or cash flows.
On January 1, 2016, the Partnership adopted a new accounting standard using a retrospective approach that required the
presentation of the Partnership's debt issuance costs as a direct deduction from the related debt liability, rather than recorded as an
asset. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $0.2 million and reduced
other assets and long-term debt (including affiliate) by $13.8 million on the Partnership’s Consolidated Balance Sheet at December
31, 2015.
Reverse Unit Split
On January 26, 2016, the board of directors of our general partner approved a 1-for-10 reverse split on our common units,
effective following market close on February 17, 2016. Pursuant to the authorization provided, the Partnership completed the 1-
for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange
on February 18, 2016. As a result of the reverse unit split, every 10 outstanding common units were combined into one common
unit. The reverse unit split reduced the number of common units outstanding from 122.3 million units to approximately 12.2
million units. All units and per unit data included in the December 31, 2015 consolidated financial statements were retroactively
restated to reflect the reverse unit split.
Use of Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in
the accompanying Consolidated Balance Sheets 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.
Business Combinations
For purchase acquisitions accounted for as business combinations, the Partnership is required to record the assets acquired,
including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based
on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation
techniques.
Fair Value
The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is
defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date. See "Note 12. Fair Value Measurements."
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.
79
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
• 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 instruments whose value is determined using
pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the
determination of fair value requires significant management judgment or estimation.
Cash and Cash Equivalents
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be
cash equivalents.
Accounts Receivable
Accounts receivable from the Partnership’s lessees and customers do not bear interest. Receivables are recorded net of the
allowance for doubtful accounts in the accompanying Consolidated Balance Sheets. The Partnership evaluates the collectability
of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its accounts receivable and when
it becomes aware of a specific lessee’s or customer’s inability to meet its financial obligations to the Partnership, such as in the
case of bankruptcy filings or deterioration in the lessee’s or customer’s operating results or financial position, the Partnership
records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. The
reserve is recognized as a reduction in the accounts receivable and an increase in operating and maintenance expenses or operating
and maintenance expenses—affiliates. Accounts are charged off when collection efforts are complete and future recovery is
doubtful. The allowance for doubtful accounts included in the Partnership's net accounts receivable balance (including affiliates)
was $4.6 million and $5.3 million at December 31, 2016 and December 31, 2015, respectively. A significant amount of the
Partnership's allowance for doubtful accounts relates to allowances for doubtful coal-related receivables.
Inventory
Inventories are stated at the lower of cost or market. The cost of aggregates and asphalt components such as stone, sand, and
recycled and liquid asphalt is determined by the first-in, first-out (FIFO) method. Cost includes all direct materials, direct labor
and related production overheads based on normal operating capacity. The cost of supplies inventory is determined by the average
cost method and includes operating and maintenance supplies to be used in the Partnership’s aggregates operations.
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 aggregate processing and transportation
infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including
interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded
at cost and are depreciated on a straight-line basis over their useful lives generally as follows:
Buildings and improvements
Machinery and equipment
Leasehold improvements
Years
20 to 40
5 to 12
Life of Lease
The Partnership begins capitalizing mine development costs at its aggregates operations at a point when reserves are
determined to be proven or probable, economically mineable and when demand supports investment in the market. Capitalization
of these costs ceases when production commences. Mine development costs are amortized based on production over the estimated
life of mineral reserves and amortization is included as a component of depreciation expense.
80
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined
in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.
Intangible Assets
The Partnership’s intangible assets consist primarily of contracts that at acquisition were more favorable for the Partnership
than prevailing market rates, known as above-market contracts. 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 except that a minimum amortization is calculated on a straight-line basis for temporarily
idled assets.
Asset Impairment
The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These
procedures are performed throughout the year and are based on historic, current and future performance and are designed to be
early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers
both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash
flows from its use and disposition 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.
In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production
ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property.
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 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.
Revenue Recognition
Coal Royalty and Other Revenues. Coal royalty and other revenues are recognized on the basis of tons of mineral sold by
our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a
percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons
of material processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees
of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per
ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees
are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and
processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms
of the transportation contracts, the Partnership receives a fixed price per ton for all material transported on the beltlines.
Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which
are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as deferred
revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon
the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately
following the expiration of the lessee’s ability to recoup the payments.
Oil and gas related revenues consist of revenues from royalties and overriding royalties. Oil and gas royalty revenues 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.
81
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Equity in Earnings from Ciner Wyoming. The Partnership accounts for non-marketable equity investments using the equity
method of accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee.
Significant influence generally exists if the Partnership has an ownership interest representing between 20% and 50% of the voting
stock of the investee. The Partnership accounts for its investment in Ciner Wyoming 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 hypothetically allocated first to identified tangible assets and liabilities, then to
finite-lived intangibles or indefinite-lived intangibles and the balance is attributed to goodwill. The portion of the basis difference
attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived
intangibles, if any, and goodwill are not amortized. The amortization of the basis difference is recorded as a reduction of earnings
from the equity investment in the Consolidated Statements of Comprehensive Income.
Our carrying value in Ciner Wyoming is reflected in the caption "Equity in unconsolidated investments" in our Consolidated
Balance Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming is reflected in the Consolidated Statements of
Comprehensive Income as revenues and other income under the caption ‘‘Equity in earnings of Ciner Wyoming." Our share of
investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the
proportionate share of the investee’s net assets, which has been allocated to the fair value of net identified tangible and finite-lived
intangible assets and amortized over the estimated lives of those assets.
VantaCore Revenues. Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer
of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction
contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to
the estimated total costs for each contract. That method is used since the Partnership considers total cost to be the best available
measure of progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which
such losses are determined. Changes in job performance, job conditions and estimated profitability, including those arising from
final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are
determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect
labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as
incurred.
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 Coal Royalty and Other revenues and in Operating and maintenance expenses, respectively, in the
Consolidated Statements of Comprehensive Income.
Transportation Revenue and Expense
The Company records transportation revenue and pays transportation costs to a Foresight affiliate to operate equipment on
behalf of the Company. The revenue and expenses related to these transactions are recorded as Coal Royalty and Other—affiliates
revenues and Operating and maintenance expenses—affiliates in the Consolidated Statements of Comprehensive Income. Shipping
and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as VantaCore revenues and
Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income. Shipping and handling revenue
included in VantaCore revenues was $36.0 million, $42.6 million and $14.0 million for the years ended December 31, 2016, 2015
and 2014, respectively. Shipping and handling costs included in Operating and maintenance expenses was $35.9 million, $42.1
million and $13.9 million for the years ended December 31, 2016, 2015, and 2014, respectively.
82
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Unit-Based Compensation
The Partnership has awarded unit-based compensation in the form of phantom units that are more fully described in Note 16.
Unit-Based Compensation. A summary of our accounting policy for unit-based awards follows.
The Partnership accounts for awards relating to its unit-based Long-Term Incentive Plan using the fair value method, which
requires the Partnership to estimate the fair value of the grant, and charge or credit the estimated fair value to expense over the
requisite service period of the grant based on fluctuations in the Partnership’s common unit price. In addition, estimated forfeitures
are included in the periodic computation of the fair value of the liability and the fair value is recalculated at each reporting date
over the service or vesting period of the grant.
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These
costs are amortized over the term of the debt. Deferred financing costs for existing debt agreements are included as a a direct
deduction from the related debt liability on the Partnership's Consolidated Balance Sheets. Deferred financing costs that the
Partnership has incurred related to its restructuring efforts are included in Other Assets on the Partnership's Consolidated Balance
Sheets until the related debt agreement has been executed.
Income Taxes
The Partnership is not subject to federal or material state income taxes, as the partners 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 bases and financial reporting bases of assets and liabilities. In the event of
an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s
income is ultimately sustained by the taxing authorities.
Lessee Audits and Inspections
The Partnership periodically audits lessee information by examining certain records and internal reports of its lessees. The
Partnership’s regional managers also perform periodic mine inspections to verify that the information that has been reported to
the Partnership is accurate. The audit and inspection processes are designed to identify material variances from lease terms as well
as differences between the information reported to the Partnership and the actual results from each property. Audits and inspections,
however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in
a reporting period different from when the revenue was initially recorded. Typically there are no material adjustments from this
process.
Recently Issued Accounting Standards
The Financial Accounting Standards Board ("FASB") issued guidance that requires an entity's management to evaluate, for
each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as
a going concern within one year after the financial statements are issued. Additional disclosures are required if management
concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The Partnership
adopted this guidance on December 31, 2016. For additional information, see Management’s Going Concern Analysis located in
this footnote above.
83
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The FASB issued authoritative guidance on revenue recognition. The core principle of this guidance is that an entity should
recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration
to which the entity expects to be entitled in exchange for those goods or services. The guidance will also require enhanced
disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance
guidance for multiple-element arrangements. The Partnership is required to adopt this guidance in the first quarter of 2018 using
one of two retrospective application methods. The Partnership has performed revenue scoping procedures to identify the contracts
for all of its revenue streams and utilized the practical expedient of grouping contracts or performance obligations with similar
characteristics as prescribed by the new standard. The Partnership is currently evaluating these contracts and while the effect of
adoption is unknown, it is not currently aware of any material changes that would result from adoption of this new revenue
recognition guidance and expects to complete its assessment of how it will be affected in the second quarter of 2016. The Partnership
anticipates utilizing the full retrospective adoption method for financial statement comparability and electing the practical expedient
of not restating contracts that begin and are completed within the same annual reporting period.
The FASB issued authoritative guidance which intended to simplify the measurement of inventory. This guidance requires
an entity to measure inventory at the lower of cost or net realizable value, and defines net realizable value as the estimated selling
price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This guidance
is effective for annual and interim periods beginning after December 15, 2016. The Partnership does not expect for the adoption
of this guidance to have a material impact on its consolidated financial statements.
The FASB issued authoritative lease guidance that requires lessees to recognize assets and liabilities on the balance sheet
for the present value of the rights and obligations created by all leases with terms of more than 12 months. The guidance also
requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows
arising from leases. The guidance is effective for annual and interim periods ending after December 31, 2018. The Partnership is
currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.
The FASB issued authoritative guidance that replaces the incurred loss impairment methodology in the current standard with
a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable
information to inform credit loss estimates. The guidance is effective for annual and interim periods ending after December 31,
2019. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.
The FASB issued authoritative guidance to clarify how certain cash receipts and cash payments are presented and classified
in the statement of cash flows in order to reduce current and potential future diversity in practice. The guidance is effective for
annual and interim periods ending after December 31, 2017. The Partnership is currently evaluating the impact of the provisions
of this guidance on its consolidated financial statements.
3. Discontinued Operations
In June 2016, NRP Oil and Gas signed a definitive agreement to sell its non-operated oil and gas working interest assets
assets for $116.1 million in gross sales proceeds, and the Partnership determined it met the criteria required for held for sale
classification. In July 2016, NRP Oil and Gas closed this transaction, which had an effective date of April 1, 2016.
The Partnership's exit from its non-operated oil and gas working interest business represented a strategic shift to reduce debt
and focus on its construction aggregates, soda ash and coal royalty and other business segments. As a result, the Partnership
classified the operating results, cash flows and assets and liabilities of its non-operated oil and gas working interest assets as
discontinued operations in its consolidated statements of comprehensive income and consolidated statements of cash flows for all
periods presented. The Partnership transitioned the remaining investments in royalty interests in oil and natural gas properties into
the Coal Royalty and Other operating segment during the third quarter of 2016.
84
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table (in thousands) presents summarized financial results of the Partnership's discontinued operations in the
Consolidated Statements of Comprehensive Income:
Revenues and other income:
Oil and gas
Gain on asset sales
Total revenues and other income
Operating expenses:
Operating and maintenance expenses (including affiliates)
Depreciation, depletion and amortization
Asset impairments
Total operating expenses
Interest expense
Income (loss) from discontinued operations
For the Years Ended December 31,
2016
2015
2014
$
$
$
16,486
8,274
24,760
$
48,750
451
49,201
11,503
7,527
564
19,594
19,724
39,912
297,049
356,685
(3,488)
1,678
$
(4,065)
(311,549) $
48,834
—
48,834
18,073
17,982
—
36,055
(662)
12,117
The following table (in thousands) presents the carrying amounts of the Partnership's assets and liabilities of discontinued
operations in the Consolidated Balance Sheets:
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable, net (including affiliates) (1)
Other
Total current assets
Mineral rights, net
Other non-current assets
Total assets of discontinued operations
LIABILITIES
Current liabilities:
Other (including affiliates) (1)
Total current liabilities
Long-term debt, net (2)
Other non-current liabilities
Total liabilities of discontinued operations
December 31,
2016
2015
$
$
$
$
— $
991
—
991
—
—
991
353
353
—
—
353
$
$
$
10,569
7,053
222
17,844
109,505
657
128,006
4,388
4,388
83,600
1,637
89,625
(1) See Note 13. Related Party Transactions for additional information on the Partnership's related party assets and liabilities.
(2) The Partnership identified the RBL Facility as specifically attributed to its non-operated oil and gas working interest
assets and included the interest from this debt in discontinued operations. See Note 11. Debt and Debt—Affiliate for
additional information on the Partnership's debt related to discontinued operations.
The following table (in thousands) presents supplemental cash flow information of the Partnership's discontinued operations:
Cash paid for interest
Plant, equipment and mineral rights funded with accounts payable or
accrued liabilities
For the Years Ended December 31,
2016
2015
2014
$
1,906
$
2,755
$
322
—
1,645
11,879
85
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Capital expenditures related to the Partnership's discontinued operations were $1.4 million, $30.6 million and $359.9 million
during the years months ended December 31, 2016, 2015 and 2014, respectively.
4. Segment Information
The Partnership's segments are strategic business units that offer products and services to different customer segments in
different geographies within the U.S. and that are managed accordingly. NRP has the following three operating segments:
Coal Royalty and Other—consists primarily of coal royalty and coal related transportation and processing assets. Other
assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. The Partnership's coal reserves are
primarily located in Appalachia, the Illinois Basin and the Western United States. The Partnership's aggregates and industrial
minerals are located in a number of states across the United States. The Partnership's oil and gas royalty assets are located in
Louisiana.
Soda Ash—consists of the Partnership's 49% non-controlling equity interest in a trona ore mining operation and soda ash
refinery in the Green River Basin, Wyoming. Ciner Resources LP, the Partnership's operating partner, mines the trona, processes
it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. The
Partnership receives regular quarterly distributions from this business.
VantaCore—consists of the Partnership's construction materials business that operates hard rock quarries, an underground
limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia,
Tennessee, Kentucky and Louisiana.
Direct segment costs and certain costs incurred at a corporate level that are identifiable and that benefit the Partnership's
segments are allocated to the operating segments. These allocated costs include costs of: taxes, legal, information technology and
shared facilities services and are included in Operating and maintenance expenses and Operating and maintenance expenses—
affiliates on the Consolidated Statements of Comprehensive Income. Intersegment sales are at prices that approximate market.
Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these
departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other corporate-
level activity not specifically allocated to a segment.
86
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands):
December 31, 2016
For the Year Ended
Operating Segments
Coal Royalty
and Other
Soda Ash
VantaCore
Corporate
and
Financing
Total
Revenues (including affiliates)
Intersegment revenues (expenses)
Gain on asset sales
Operating and maintenance expenses
(including affiliates)
General and administrative (including affiliates)
Depreciation, depletion and amortization
(including affiliates)
Asset impairment
Other expense, net
Net income (loss) from continuing operations
Net income from discontinued operations
Capital expenditures
Total assets of continuing operations at December 31,
2016
Total assets of discontinued operations at December
31, 2016
$
$ 210,115
150
29,068
40,061
—
—
$ 120,802
(150)
13
$
— $ 370,978
—
—
29,081
—
29,890
—
31,766
15,861
—
161,816
—
5
—
—
100,656
—
—
20,570
130,546
20,570
—
—
—
40,061
—
—
14,506
1,065
—
4,438
—
5,380
—
—
90,531
(111,101)
—
—
46,272
16,926
90,531
95,214
1,678
5,385
990,172
255,901
190,615
7,002
1,443,690
—
—
—
—
991
December 31, 2015
Revenues (including affiliates)
Intersegment revenues (expenses)
Gain (loss) on asset sales
Operating and maintenance expenses
(including affiliates)
General and administrative (including affiliates)
Depreciation, depletion and amortization
(including affiliates)
Asset impairment
Other expense, net
Net income (loss) from continuing operations
Net loss from discontinued operations
Capital expenditures
Total assets of continuing operations at December 31,
2015
Total assets of discontinued operations at December
31, 2015
$
$ 243,781
21
6,936
49,918
—
—
$ 139,049
(21)
(36)
$
— $ 432,748
—
—
6,900
—
35,321
—
45,338
378,327
—
(208,248)
—
428
—
—
116,945
—
—
12,348
152,266
12,348
—
—
—
49,918
—
—
15,578
6,218
—
251
—
14,039
—
—
89,744
(102,092)
60,916
384,545
89,744
(260,171)
— (311,549)
14,467
—
1,078,778
261,942
200,348
961
1,542,029
—
—
—
—
128,006
December 31, 2014
Revenues (including affiliates)
Gain on asset sales
Operating and maintenance expenses
(including affiliates)
General and administrative (including affiliates)
Depreciation, depletion and amortization
(including affiliates)
Asset impairment
Other expense, net
Net income (loss) from continuing operations
Net income from discontinued operations
Capital expenditures
$ 266,085
1,366
$
41,416
—
$
—
—
—
—
—
41,416
—
—
37,407
—
58,598
26,209
—
145,237
—
5,351
87
42,031
20
38,723
—
3,296
—
—
32
—
171,116
$
— $ 349,532
1,386
—
—
10,545
—
—
79,427
(89,972)
—
—
76,130
10,545
61,894
26,209
79,427
96,713
12,117
176,467
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
5. Acquisitions and Divestitures
Acquisitions
On October 1, 2014, the Partnership completed its acquisition of VantaCore for total consideration of $200.6 million in cash
and common units. The Partnership funded this acquisition through the borrowing of $169.0 million under its Opco’s revolving
credit facility and the issuance of 0.2 million common units to certain of the sellers. Revenue and operating income from VanataCore
included in the Consolidated Statements of Comprehensive Income were $42.1 million and $0.1 million, respectively, for the year
ended December 31, 2014.
On November 12, 2014, the Partnership completed its acquisition of non-operated oil and gas working interests in the Sanish
Field of the Williston Basin from an affiliate of Kaiser-Francis Oil Company for $339.1 million. These non-operated working
interest assets were sold during 2016 as discussed in Note 3. Discontinued Operations. The Partnership funded this acquisition
using the net proceeds from the issuance of additional $125 million principal amount of its 9.125% Senior Notes due 2018,
borrowing $117.0 million under an NRP Oil and Gas revolving credit facility and proceeds of $100.4 million from a public common
unit offering. Revenue and operating income from these acquired oil and gas assets included in the Consolidated Statements of
Comprehensive Income were $12.8 million and $3.7 million, respectively, for the year ended December 31, 2014.
These acquisitions were accounted for under the acquisition method of accounting for businesses. Accordingly, the Partnership
conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at
their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were
expensed as incurred. The results of operations of all acquisitions have been included in the consolidated financial statements since
the acquisition dates. The following unaudited pro forma financial information (in thousands) presents a summary of the
Partnership’s consolidated revenues, net income and net income per common unit for the twelve months ended December 31, 2014
assuming the VantaCore and Sanish Field acquisitions had been completed as of January 1, 2014, including adjustments to reflect
the values assigned to the net assets acquired:
Total revenues and other income
Net income
Basic and diluted net income per common unit
Divestitures
For the Year ended
December 31, 2014
533,517
$
$
$
122,319
9.90
As discussed in Note 2. Summary of Significant Accounting Policies, the Partnership has been and is currently pursuing or
considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments
which could otherwise cause the Partnership to breach financial covenants under its debt agreements, and mitigate the effects of
scheduled debt principal payments that will strain the Partnership's liquidity. As part of this plan, the Partnership completed the
sale of the following assets during the year ended December 31, 2016:
1) Oil and gas working interest in the Williston Basin for $116.1 million gross sales proceeds, as discussed in Note 3.
Discontinued Operations.
2) 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.
3) Aggregate 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.
4) In addition to the 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 cumulative $17.3 million of gross sales
proceeds and recorded $8.6 million of cumulative gain from these sale transactions that are included in Gain on asset sales, net
88
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
Additional asset sales during the year included sales of land and plant and equipment within the Coal Royalty and Other
segment for $1.2 million of gross proceeds and a $0.3 million of cumulative gain from these transactions that are included in Gain
on asset sales, net on the Consolidated Statement of Comprehensive Income.
During the year ended December 31, 2015, the Partnership sold mineral reserves in multiple transactions for cumulative
$3.5 million of gross sales proceeds and recorded a $3.3 million gain on asset sales included in Gain on asset sales, net on its
Consolidated Statement of Comprehensive Income. The Partnership sold intangible assets for $4.4 million in gross proceeds and
recorded a gain of $3.1 million included in Gain on asset sales, net in the Consolidated Statement of Comprehensive Income. The
Partnership also sold plant and equipment $6.7 million of gross proceeds and recorded a gain of $0.6 million included in Gain on
asset sales, net on the Consolidated Statement of Comprehensive Income.
During the year ended December 31, 2014, the Partnership sold land and mineral reserves for $1.4 million in gross sales
proceeds and recorded a cumulative gain of $1.4 million on these asset sales included in Gain on asset sales, net on its Consolidated
Statement of Comprehensive Income.
6. Equity Investment
The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Ciner Wyoming
distributed $46.6 million, $46.8 million and $46.6 million to the Partnership in the year ended December 31, 2016, 2015 and 2014,
respectively.
The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying
equity in Ciner Wyoming's net assets was $150.0 million and $154.8 million as of December 31, 2016 and 2015, respectively.
This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to
property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years.
The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method.
The Partnership's equity in the earnings of Ciner Wyoming is summarized as follows (in thousands):
Income allocation to NRP’s equity interests (1)
Amortization of basis difference
Equity in earnings of unconsolidated investment
For the Year Ended December 31,
2016
2015
2014
$
$
44,882
(4,821)
40,061
$
$
54,709
(4,791)
49,918
$
$
47,354
(5,938)
41,416
(1) Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $0.9
million, $0.7 million and $0.5 million for the year ended December 31, 2016, 2015 and 2014, respectively.
The results of Ciner Wyoming’s operations are summarized as follows (in thousands):
Sales
Gross profit
Net Income
For the Year Ended December 31,
$
$
2016
475,187
114,232
91,596
$
2015
486,393
131,493
111,650
2014
465,032
118,439
96,640
89
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The financial position of Ciner Wyoming is summarized as follows (in thousands):
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
$
December 31,
$
2016
134,616
235,427
55,396
98,425
2015
144,695
233,845
43,018
116,808
The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming required the Partnership to pay
additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement
were met by Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014, 2015 and 2016, the Partnership
paid contingent consideration of $0.5 million, $3.8 million and $7.2 million, respectively, in contingent consideration to Anadarko
for performance criteria met by Ciner Wyoming in 2013, 2014 and 2015, respectively. The Partnership has no further contingent
consideration payments due to Anadarko under the purchase agreement.
7. Inventory
The components of inventories at December 31, 2016 and 2015 are as follows (in thousands):
Aggregates
Supplies and parts
Total inventory
8. Plant and Equipment
The Partnership’s plant and equipment consist of the following (in thousands):
Plant and equipment at cost
Construction in process
Less accumulated depreciation
Total plant and equipment, net
December 31,
2016
2015
6,037
856
6,893
$
$
7,056
779
7,835
December 31,
2016
2015
79,171
$
557
(30,285)
49,443
$
92,049
646
(32,020)
60,675
$
$
$
$
Depreciation expense related to the Partnership's plant and equipment totaled $12.4 million, $15.9 million and $7.6 million
for the year ended December 31, 2016, 2015 and 2014, respectively.
Impairment expense related to the Partnership's plant and equipment totaled $3.1 million, $7.7 million, and $0.8 million and
are included in Asset impairments in the Consolidated Statements of Comprehensive Income for the year ending December 31,
2016, 2015 and December 31, 2014, respectively. During 2016, the Partnership recorded a $2.0 million impairment expense in its
Coal Royalty and Other segment primarily related to a coal preparation plant and a $1.1 million impairment expense in its VantaCore
segment primarily related to equipment write-downs. During the second quarter of 2015 the Partnership recorded a $2.3 million
impairment expense related to a coal preparation plant and during the fourth quarter of 2015 the Partnership recorded a $4.7 million
impairment expense related to coal processing and transportation assets and obsolete equipment. During 2015, the Partnership
also recorded a $0.7 million impairment expense related to obsolete plant and equipment at VantaCore.
90
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9. Mineral Rights
The Partnership’s mineral rights consist of the following (in thousands):
For the Year Ended December 31, 2016
Coal properties
Aggregates properties
Oil and gas royalty properties
Other
Total
Coal properties
Aggregates properties
Oil and gas royalty properties
Other
Total
$
$
$
Carrying Value
$ 1,170,904
176,774
12,395
14,946
$ 1,375,019
Accumulated
Depletion
(420,032) $
(39,056)
(6,289)
(1,450)
(466,827) $
Net Book Value
750,872
137,718
6,106
13,496
908,192
For the Year Ended December 31, 2015
Accumulated
Depletion
Carrying Value
$ 1,169,718
206,309
38,885
14,947
$ 1,429,859
$
(398,235) $
(35,752)
(9,994)
(1,356)
(445,337) $
Net Book Value
771,483
170,557
28,891
13,591
984,522
Depletion expense related to the Partnership’s mineral rights totaled $29.8 million, $40.4 million and $50.6 million for the
year ended December 31, 2016, 2015 and 2014, respectively.
Impairment of Mineral Rights
The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These
procedures are performed throughout the year and consider both quantitative and qualitative information based on historic, current
and future performance and are designed to identify impairment indicators. If an impairment indicator is identified, additional
evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed
impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value.
Impairment is measured based on the estimated fair value, which is primarily determined based upon the present value of the
projected future cash flow compared to the assets’ carrying value. The Partnership believes its estimates of cash flows and discount
rates are consistent with those of principal market participants. The inputs used by management for fair value measurements include
significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement for these types of
assets. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or
production ceasing on a property for an extended period may require that a separate impairment evaluation be completed on a
significant property.
91
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the years ended December 31, 2016, 2015 and 2014, the Partnership identified facts and circumstances that indicated
that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment
expense as follows (in thousands):
Impaired Asset Description
Coal properties (1)
Oil and gas properties (2)
Aggregates royalty properties (3)
Total
For the years ended December 31,
2016
12,088
36
1,677
13,801
$
$
2015
257,468
70,527
43,402
371,397
$
$
2014
16,793
—
3,013
19,806
$
$
(1) 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 recorded at fair value was $4.0 million
at September 30, 2016. The Partnership recorded $8.2 million of coal property impairment during the three months ended
December 31, 2016 and the fair value of the impaired asset recorded at fair value was $0.0 million at December 31, 2016.
Total coal property impairment expense for the year ended December 31, 2015 was $257.5 million. The Partnership recorded
$1.5 million of coal property impairment during the three months ended June 30, 2015 and the fair value measurement of
these impaired assets recorded at fair value was $0.0 million at June 30, 2015. The Partnership recorded $247.8 million of
coal property impairment during the three months ended September 30, 2015 and the fair value of these impaired assets
recorded at fair value was $28.4 million at September 30, 2015. The Partnership recorded the remaining $8.2 million of
coal property impairment during the three months ended December 31, 2015 and the fair value of these impaired assets
recorded at fair value was $0.4 million at December 31, 2015. These impairments primarily resulted from the continued
deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand,
sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared
net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost
exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of net capitalized cost
over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and
useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the
measurement date and included an adjustment for risk related to the future realization of cash flows.
Total coal property impairment expense for the year ended December 31, 2014 was $16.8 million. This expense was
recorded during the fourth quarter of 2014 when management concluded certain unleased properties were impaired due
primarily to the ongoing regulatory environment and continued depressed coal markets with little indications of
improvement in the near term. The fair values for those unleased properties were determined for the associated reserves
using Level 2 market approaches based upon recent comparable sales and Level 3 expected cash flows.
(2) The Partnership recorded $36 thousand of oil and gas royalty asset impairment during the year ended December 31, 2016.
Total oil and gas royalty asset impairment expense for the year ended December 31, 2015 was $70.5 million. The Partnership
recorded this impairment during the three months ended September 30, 2015. The fair value measurement of these impaired
assets recorded at fair value were $13.0 million at September 30, 2015. This impairment primarily resulted from declines
in future expected realized commodity prices and reduced expected drilling activity on its acreage. NRP compared net
capitalized costs of its oil and gas royalty properties to estimated undiscounted future net cash flows. If the net capitalized
cost exceeded the undiscounted future net cash flows, the Partnership recorded an impairment for the excess of net capitalized
cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine
the fair value include estimates of: (i) oil and gas reserves and risk-adjusted probable and possible reserves; (ii) future
commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying
commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX
forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials.
(3) The Partnership recorded $1.7 million of aggregates royalty property impairments during the year ended December 31,
2016. Total aggregates property impairment expense for the year ended December 31, 2015 was $43.4 million.This
impairment was recorded during the three months ended September 30, 2015. The fair value measurement of these impaired
assets recorded at fair value was $13.1 million at September 30, 2015. This impairment primarily resulted from greenfield
development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties
92
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its
aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted
cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash
flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash
flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current
realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash
flows. Total aggregates property impairment expense for the year ended December 31, 2014 was $3.0 million.
10. Goodwill and Intangible Assets (Including Affiliate)
The Partnership's intangible assets—affiliate relate to above market coal transportation contracts with subsidiaries of
Foresight Energy LP ("Foresight Energy") in which the Partnership receives throughput fees for the handling and transportation
of coal as follows (in thousands):
Intangible assets—affiliate
Less accumulated amortization—affiliate
Total intangible assets, net—affiliate
December 31,
2016
2015
$
$
81,109
(31,298)
49,811
$
$
81,109
(28,112)
52,997
Amortization expense related to the Partnership's intangible assets—affiliate totaled $3.2 million, $3.6 million and $3.3
million for the years ended December 31, 2016, 2015 and 2014, respectively.
The Partnership's intangible assets consist of permits, aggregate-related trade names and other agreements as follows (in
thousands):
Intangible assets
Less accumulated amortization
Total intangible assets, net
December 31,
2016
2015
$
$
5,227
(1,991)
3,236
$
$
5,076
(1,146)
3,930
Amortization expense related to the Partnership's intangible assets totaled $0.8 million, $1.0 million and $0.3 million for
the years ended December 31, 2016, 2015 and 2014, respectively.
During the second quarter of 2014, the Partnership and a lessee amended an aggregates lease in its Coal Royalty and Other
segment, which led the Partnership to conclude an impairment triggering event had occurred. Fair value of the lease agreement
was determined using Level 3 expected cash flows. The resulting impairment expense of $5.6 million is included in Asset
impairments on the Consolidated Statements of Comprehensive Income.
The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject
to revision as those plans change in future periods.
For the Year Ended December 31,
2017
2018
2019
2020
2021
Estimated Amortization Expense
(in thousands)
$
3,559
3,289
3,275
3,280
3,280
The weighted average remaining amortization period for contract intangibles and other intangibles was 28 years and 16
years, respectively.
93
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the fourth quarter of 2014, $52.0 million of goodwill was added relating to the VantaCore acquisition. This amount
represented the preliminary residual value. During 2015, the purchase price allocation was adjusted as more detailed analysis was
completed and additional information was obtained about the facts and circumstances for VantaCore’s property, plant and equipment,
right to mine assets and asset retirement obligations that existed as of the acquisition date. These adjustments decreased goodwill
by $46.5 million and resulted in an acquisition date goodwill of $5.5 million.
During the fourth quarter of 2015, the Partnership evaluated goodwill for impairment and compared the estimated fair value
of the VantaCore reporting unit to its carrying amount. The carrying amount exceeded fair value and the Partnership recorded a
$5.5 million goodwill impairment expense include in Asset impairments on the Partnership's Consolidated Statements of
Comprehensive Income. The lower fair value was primarily a result of the deterioration in certain regional markets in which
VantaCore operates causing a decline in future performance levels compared to levels estimated during the purchase price allocation
process. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include
estimates of future cash flow, discount rate and useful economic life. These estimates were based on current conditions and historical
experience applied to develop projections of future operating performance.
94
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
11. Debt and Debt—Affiliate
As of December 31, 2016 and 2015, Debt and debt—affiliate consisted of the following (in thousands):
NRP LP debt (1):
9.125% senior notes, with semi-annual interest payments in April and October, due
October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% (2)
$
425,000
$
425,000
December 31,
2016
2015
Opco debt (1):
Revolving credit facility, due June 2018 (2)
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
5.31% utility local improvement obligation, with annual principal and interest
payments in February, due March 2021
NRP Oil and Gas debt:
Revolving credit facility
Total debt at face value
Net unamortized debt discount
Net unamortized debt issuance costs (1)
Total debt, net
Less: current portion of long-term debt
Less: debt classified as non-current liabilities of discontinued operations
Total long-term debt
210,000
290,000
9,187
64,029
30,633
18,825
52,204
13,850
85,714
38,462
21,600
60,000
119,524
135,000
36,272
40,909
134,035
148,077
38,262
961
—
1,138,932
(1,322)
(11,307)
1,126,303
$
$
138,903
—
42,308
1,153
85,000
1,387,073
(2,077)
(14,040)
1,370,956
80,745
83,600
987,400
$
1,206,611
$
$
$
(1) See Note 2. Summary of Significant Accounting Policies for discussion of debt issuance costs reclassification upon adoption
of new accounting standard on January 1, 2016.
(2) See Note 19. Subsequent Events for discussion of the March 2017 recapitalization transactions.
95
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NRP LP Debt
NRP 2018 Senior Notes
In September 2013, the Partnership, together with NRP Finance Corporation ("NRP Finance"), a wholly owned subsidiary
of the Partnership, as co-issuer, issued $300.0 million of 9.125% Senior Notes at an offering price of 99.007% of par (the "NRP
2018 Senior Notes"). Net proceeds after expenses from the issuance of NRP 2018 Senior Notes were approximately $289.0 million.
The NRP 2018 Senior Notes call for semi-annual interest payments on April 1 and October 1 of each year, and will mature on
October 1, 2018. None of the Partnership's subsidiaries guarantee the NRP 2018 Senior Notes.
In October 2014, the Partnership, together with NRP Finance as co-issuer, issued an additional $125.0 million of the NRP
2018 Senior Notes at an offering price of 99.5% of par. The additional issuance constituted the same series of securities as the
existing NRP 2018 Senior Notes. Net proceeds of $122.6 million from the additional issuance of the NRP 2018 Senior Notes were
used to fund a portion of the purchase price of NRP’s acquisition of non-operated working interests in oil and gas assets located
in the Williston Basin in North Dakota.
The Partnership and NRP Finance have the option to redeem the NRP 2018 Senior Notes, in whole or in part, at any time
on or after April 1, 2016, at fixed redemption prices specified in the indenture governing the NRP 2018 Senior Notes (the "2018
Indenture"). The 2018 Indenture contains covenants that, among other things, limit the ability of the Partnership and certain of its
subsidiaries to incur or guarantee additional indebtedness. Under the 2018 Indenture, the Partnership and certain of its subsidiaries
generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as
defined in the indenture) is at least 2.0 to 1.0 for the four preceding full fiscal quarters. The ability of the Partnership and certain
of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of the Partnership and
certain of its subsidiaries that is senior to the Partnership's unsecured indebtedness exceeds certain thresholds.
Opco Debt
All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its
wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of December 31, 2016 and 2015, Opco was
in compliance with the terms of the financial covenants contained in its debt agreements.
Opco Credit Facility
In June 2016, Opco entered into the first amendment (the "First Amendment") to its Amended and Restated Credit Agreement
(the "Opco Credit Facility") that is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of
the assets of Opco and its subsidiaries, as further described below. Under the First Amendment:
• The maturity date of the Opco Credit Facility was extended from October 1, 2017 to June 30, 2018;
• The maximum leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Opco Credit
Facility) has been amended to remain at 4.0x for the remaining term of the Opco Credit Facility;
• The asset sale covenant was amended to allow asset sales of up to $300.0 million from and after the effective date of
the First Amendment; provided, however, that 75% of the net cash proceeds of any such asset sales must be used to
repay the Opco Credit Facility (without any corresponding commitment reduction) and/or NRP Opco’s Senior Notes
described below.
On the effective date of the First Amendment, the total commitment under the Opco Credit Facility was reduced from $300.0
million to $260.0 million. In addition, Opco and the lenders agreed to further reduce commitments under the Opco Credit Facility
to (a) $210.0 million on December 31, 2016, (b) $180.0 million on June 30, 2017 and (c) $150.0 million on December 31, 2017.
Opco will have the right to delay any of these commitment reductions by up to 90 days each upon the agreement of the lenders
holding 66.7% of the then-existing commitments. To the extent any such commitment reduction is extended under the terms of
the A&R Revolving Credit Facility, Opco's ability to make distributions to the Partnership will be limited to amounts necessary
for the Partnership to pay taxes and other general partnership expenses and make interest payments on its 9.125% Senior Notes
due 2018.
96
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In addition to the 4.0x leverage ratio described above, the Opco Credit Facility requires Opco to maintain a ratio of consolidated
EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less
than 3.5 to 1.0. As of December 31, 2016, Opco's leverage ratio was 2.80x, and fixed charge coverage ratio was 4.99x.
Effective on the date of the First Amendment, indebtedness under the Opco Credit Facility bears interest, at Opco's option,
at:
•
•
the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR
plus 1%, in each case plus an applicable margin ranging from 2.50% to 3.50%; or
a rate equal to LIBOR plus an applicable margin ranging from 3.50% to 4.50%.
The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for the years ended
December 31, 2016 and 2015 were 4.46% and 2.91%, respectively.
Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco
may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty.
The Opco Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s
ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Included
in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of
liquidity. The Opco Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes
(as described below).
The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $673.0
million and $709.9 million classified as Land, Plant and equipment and Mineral rights on the Partnership’s Consolidated Balance
Sheet as of December 31, 2016 and 2015, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly
owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the
personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal
royalty revenue producing properties, (4) real property associated with certain of VantaCore’s construction aggregates mining
operations, and (5) certain of Opco’s coal-related infrastructure assets.
Opco Senior Notes
Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and
principal due dates. As of December 31, 2016 and 2015, the Opco Senior Notes had cumulative principal balances of $503.0
million and $585.9 million, respectively. Opco made principal payments of $82.9 million on the Opco Senior Notes during the
year ended December 31, 2016 and $80.8 million for the years ended December 31, 2015 and 2014.
The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to:
• maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of
no more than 4.0 to 1.0 for the four most recent quarters;
•
not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as
defined in the note purchase agreement); and
• maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges
(consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.
The 8.38% and 8.92% Opco Senior Notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness
to consolidated EBITDDA (as defined in the Note Purchase Agreements) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then
in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the
notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. Opco has not
exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2016. As of December 31, 2016, Opco's
leverage ratio was 2.80x, and fixed charge coverage ratio was 4.99x.
97
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale
proceeds to make mandatory prepayment offers on the Opco Senior Notes as follows:
• Until the earlier of the time that (1) Opco has sold $300 million of assets and (2) June 30, 2020, Opco will be required
to make prepayment offers to the holders of the Opco Senior Notes using 25% of the net cash proceeds from certain
asset sales; and
• After the earlier to occur of the dates above, Opco will be required to make prepayment offers to the holders of the Opco
Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the
amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being
prepaid.
The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior
Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the
Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do
not affect the maturity dates of any series of the Opco Senior Notes.
NRP Oil and Gas Debt Classified as Liabilities of Discontinued Operations
RBL Facility
In August 2013, NRP Oil and Gas entered into the RBL Facility, a senior secured, reserve-based revolving credit facility, in
order to fund capital expenditure requirements related to the development of the oil and gas assets in which it owned non-operated
working interests. The RBL Facility was secured by a first priority lien and security interest in substantially all of the assets of
NRP Oil and Gas. NRP Oil and Gas was the sole obligor under the RBL Facility, and neither the Partnership nor any of its other
subsidiaries was a guarantor of the RBL Facility.
At December 31, 2015, there was $85.0 million respectively, outstanding under the RBL Facility. As described in Note 3.
Discontinued Operations, the Partnership included this debt and its related interest expense in discontinued operations. In July
2016, NRP Oil and Gas LLC closed the sale of its non-operated oil and gas working interest assets and used a portion of the
proceeds to repay the RBL Facility in full.
Consolidated Principal Payments
The consolidated principal payments due are set forth below (in thousands):
2017
2018
2019
2020
2021
Thereafter
NRP LP
Senior Notes
$
—
425,000
(1)
Opco
Senior Notes (2)
80,638
$
80,638
Credit Facility
60,000
$
150,000
$
—
—
—
—
76,045
54,704
47,043
164,864
—
—
—
—
$
425,000
$
503,932
$
210,000
Total
140,638
655,638
76,045
54,704
47,043
164,864
$ 1,138,932
(1) The 9.125% senior notes due 2018 were issued at a discount and were carried at $423.7 million as of December 31, 2016.
(2) Incudes $1.0 million utility local improvement obligation.
98
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
12. Fair Value Measurements
The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-
term debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable
and accounts payable approximate fair value due to their short-term nature. The following table (in thousands) shows the carrying
amount and estimated fair value of the Partnership's other financial instruments:
Debt and debt—affiliate:
NRP 2018 Senior Notes (1)
Opco Senior Notes and utility local improvement
obligation (2)
Opco Revolving Credit Facility (3)
NRP Oil and Gas RBL Facility (3)
$
$
$
Assets:
Contracts receivable—affiliate, current and long-term
(2)
December 31, 2016
December 31, 2015
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
420,097
$
412,250
$
417,296
$
277,313
500,174
206,032
$
— $
488,814
210,000
$
— $
584,890
285,170
83,600
$
$
383,065
290,000
85,000
46,742
32,554
50,366
34,498
(1) The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period
end.
(2) The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing
trading prices near period end.
(3) The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective
of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.
13. Related Party Transactions
Reimbursements to Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural
Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed
for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals
Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, provide
their services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary
and benefits costs related to their employee services provided to NRP. In addition, the Partnership receives non-cash equity
contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the
Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners'
Capital and were $0.3 million and $0.8 million during the years ended December 31, 2016 and 2015, respectively. These QMC
and WPPLP employee management service costs and non-cash equity compensation expenses are presented as Operating and
maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of
Comprehensive Income. NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These
overhead costs include certain 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, net and General and administrative—affiliates on the Consolidated Statements
of Comprehensive Income.
The Partnership had Accounts payable—affiliates to QMC of $0.4 million and $1.1 million, including less than $0.1 million
and $0.6 million related to discontinued operations at December 31, 2016 and 2015, respectively, for services provided by QMC
to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.6 million and $0.3 million at December 31,
2016 and 2015, respectively.
99
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Direct general and administrative expenses charged to the Partnership by WPPLP and QMC are as follows (in thousands):
Operating and maintenance expenses—affiliates, net
General and administrative—affiliates
For the Year Ended
December 31,
2016
2015
2014
9,891
3,591
10,063
5,312
9,166
3,258
Included in income (loss) from discontinued operations are $1.3 million, $0.7 million and $0.6 million of operating and
maintenance expenses charged by QMC for the year ended December 30, 2016, 2015 and 2014, respectively.
Cline Affiliates
Various companies affiliated with Chris Cline, including Foresight Energy LP, lease coal reserves from the Partnership, and
the Partnership also leases coal transportation assets to them for a fee. Mr. Cline, both individually and through another affiliate,
Adena Minerals, LLC, owns a 31% interest (unaudited) in the NRP's general partner, as well as approximately 0.5 million of NRP's
common units (unaudited) at December 31, 2016.
Coal related revenues from Foresight Energy totaled $63.4 million, $86.6 million and $81.5 million for the years ended
December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016 and 2015, the Partnership had Accounts receivable
—affiliates from Foresight Energy of $6.5 million and $6.4 million, respectively. As of December 31, 2016 and 2015, the Partnership
had received $71.6 million and $82.6 million, respectively in minimum royalty payments to date that have been recorded as
Deferred revenue—affiliates since they have not been recouped by Foresight Energy.
NRP owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy's Sugar Camp mine. The
lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at December 31,
2016 were $76.4 million with unearned income of $31.8 million, and the net amount receivable was $44.6 million, of which $2.2
million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate
on the accompanying Consolidated Balance Sheets. Minimum lease payments are $5.0 million per year for the next five years and
represent a $1.25 million per quarter in deficiency payment. Total projected remaining payments under the lease at December 31,
2015 were $81.2 million with unearned income of $35.4 million and the net amount receivable was $45.9 million, of which $2.0
million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates
on the accompanying Consolidated Balance Sheets.
NRP holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based
upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty was accounted for as a
financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of December 31,
2016 was $2.7 million, of which $1.4 million is included in Accounts receivable—affiliates while the remaining is included in
Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 2015 was $4.9
million, of which $1.5 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts
receivable—affiliate on the accompanying Consolidated Balance Sheets.
NRP owns rail load out transportation assets and subcontracts out the operating responsibilities to an affiliate of Foresight
Energy at Foresight's Williamson mine. During the years ended December 31, 2016, 2015 and 2014, the Partnership recorded
operating and maintenance expenses—affiliates of $1.3 million, $1.4 million and $1.6 million, respectively, to operate these assets.
During the years ended December 31, 2016, 2015 and 2014, the Partnership recognized a gain of $0.0 million, $9.3 million
and $5.7 million, respectively on a reserve swap at Foresight Energy's Williamson mine. The gain is included in Coal royalty and
other—affiliates revenues on the Consolidated Statements of Comprehensive Income. The Level 3 fair value of the reserves was
estimated using a discounted cash flow model. The expected cash flows were developed using estimated annual sales tons,
forecasted sales prices and anticipated market royalty rates.
100
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Long-Term Debt—Affiliate
Donald R. Holcomb, one of the Partnership’s former directors, was a manager of Cline Trust Company, LLC (the "Cline
Trust Company"). As of December 31, 2015, Cline Trust Company owned approximately 0.5 million of the Partnership’s common
units and $20.0 million in principal amount of the Partnership’s 9.125% Senior Notes due 2018. As of December 31, 2015, the
members of the Cline Trust Company were four trusts for the benefit of the children of Chris Cline, each of which owns an
approximately equal membership interest in the Cline Trust Company. As of December 31, 2015, Mr. Holcomb also served as
trustee of each of the four trusts. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million
as of December 31, 2015 and was included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet.
In April 2016, Mr. Holcomb resigned from the Partnership's board of directors and as a result the $19.9 million debt balance held
by Cline Trust Company was subsequently reclassified as Long-term debt, net on the Partnership's accompanying Consolidated
Balance Sheet.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), which controls several private
equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership
adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be
pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines
set forth in the Partnership's conflicts policy.
At December 31, 2016, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp ("Corsa")., a
coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson
III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Coal related revenues from Corsa totaled $2.2 million,
$3.1 million and $3.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.
As of December 31, 2016 and 2015 the Partnership had recorded $0.0 million and $0.3 million, respectively in minimum
royalty payments to date as Deferred revenue—affiliates since they have not been recouped by Corsa. The Partnership also had
Accounts receivable—affiliates totaling $0.2 million and $0.2 million from Corsa at December 31, 2016 and 2015, respectively.
WPPLP Production Royalty and Overriding Royalty
For the year ended December 31, 2016, the Partnership recorded $0.7 million in operating and maintenance expenses—
affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in
2007. These charges were $0.4 million and zero for the years ended December 31, 2015 and 2014, respectively. The Partnership
had Other assets—affiliate from WPPLP of $1.0 million and $1.1 million at December 31, 2016 and December 31, 2015, respectively
related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.
14. Commitments and Contingencies
Legal
NRP is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate
results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a
material effect on the Partnership’s financial position, liquidity or operations.
Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants,
including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In
each case, the mine on the subject property had been closed, the property had been reclaimed, and the state reclamation bond had
been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site
could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and
reclaimed coal mine operations. A subsidiary of the Partnership has been named as a defendant in one of these lawsuits. The
Partnership currently cannot reasonably estimate a range of potential loss, if any, related to this matter.
101
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Foresight Energy Disputes
In November 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the
Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of
contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late
March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled.
In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels.
We believe the force majeure claim by Hillsboro has no merit and we are vigorously pursuing recovery against them. However,
the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency
payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with
respect to 2015 and 2016 resulted in a cumulative $46.0 million negative cash impact to us. Such amount will increase for each
quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume
coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition
could be adversely affected.
In April 2016, we filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin
County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail
loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its
recoupable balance and failure to make payments in accordance with these lease agreements has resulted in a cumulative $6.2
million negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount
has been recorded.
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 "Item
1. Business—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, 2016. 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 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. The Partnership is also responsible for losses and liabilities, including environmental
liabilities that may arise from uninsured and underinsured events at its VantaCore operations.
15. Major Customers
Revenues from customers that exceeded ten percent of total revenues and other income for any of the periods presented
below are as follows (in thousands except for percentages):
2016
2015
2014
Revenues
Percent
Revenues
Percent
Revenues
Percent
For the Years Ended December 31,
Foresight Energy
Alpha Natural Resources
$
$
63,355
18,184
15.8% $
4.5% $
86,614
34,364
19.7% $
7.8% $
81,546
48,783
23.2%
13.9%
All of the revenue related to the customers above is included in revenues of the Coal Royalty and Other segment.
102
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The Partnership had a significant concentration of revenues with Foresight Energy and Alpha Natural Resources. The exposure
is currently spread out over a number of different mining operations and leases. During the year ended December 31, 2015, total
revenues and other income from Alpha Natural Resources included a $6.0 million non-recurring lease assignment fee.
16. Unit-Based Compensation
GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the "Long-Term
Incentive Plan") for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the
Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term
Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and
the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part
of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in
any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without
the consent of the participant.
Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive
the cash equivalent to the value of a unit of the Parent common units upon each vesting. The Partnership records compensation
cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance
commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted
quarterly for any changes in the Partnership’s unit price. Under the plan a grantee will receive the market value of a common unit
in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The
compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms
as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general
partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for
any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides
otherwise.
In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem
Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the
Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting
but may be subject to forfeiture if the grantee ceases employment prior to vesting.
A summary of activity in the outstanding grants during 2016 is as follows (in thousands):
Outstanding grants at January 1, 2016
Grants during the period
Grants vested and paid during the period
Forfeitures during the period
Outstanding grants at December 31, 2016
Phantom Units
126
—
(28)
(12)
86
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The Partnership recorded a credit to
general and administrative expenses related to its Long-Term Incentive Plan of $3.4 million for the year ended December 31, 2015,
due to the decline in the market price of the Partnership's common units during 2015. For the years ended December 31, 2016 and
2014 the Partnership recorded G&A expenses of $1.4 million and $1.0 million, respectively.
In connection with the Long-Term Incentive Plans, payments are typically made during the first quarter of the year. Payments
of $1.5 million, $4.4 million and $6.5 million were made during the years ended December 31, 2016, 2015, and 2014, respectively.
The grant date fair value was $0.0 million, $4.2 million and $6.6 million for awards in 2016, 2015 and 2014, respectively. The
unaccrued cost associated with unvested outstanding grants and related DERs at December 31, 2016 and December 31, 2015, was
$0.8 million and $0.7 million, respectively.
103
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
17. Cash Distributions
The following table shows the distributions paid by the Partnership during the year ended December 31, 2016, 2015 and
2014:
2016
Date Paid
Period Covered by Distribution
Distribution per
Common Unit
Common Units
GP Interest
Total
Total Distributions (In thousands)
February 12, 2016
May 13, 2016
August 12, 2016
November 14, 2016
October 1 - December 31, 2015
January 1 - March 31, 2016
April 1 - June 30, 2016
July 1 - September 30, 2016
$
2015
February 13, 2015
May 14, 2015
August 14, 2015
October 1 - December 31, 2014
January 1 - March 31, 2015
$
April 1 - June 30, 2015
November 13, 2015
July 1 - September 30, 2015
2014
January 31, 2014
October 1 - December 31, 2013
$
May 14, 2014
August 14, 2014
January 1 - March 31, 2014
April 1 - June 30, 2014
November 14, 2014
July 1 - September 30, 2014
18. Deferred Revenue and Deferred Revenue—Affiliate
0.45
0.45
0.45
0.45
3.50
0.90
0.90
0.45
3.50
3.50
3.50
3.50
$
$
$
$
5,503
5,503
5,505
5,503
42,804
11,007
11,009
5,504
$
38,433
$
38,634
38,938
42,796
$
$
$
113
113
112
113
874
225
223
112
785
787
795
874
5,616
5,616
5,617
5,616
43,678
11,232
11,232
5,616
39,218
39,421
39,733
43,670
Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which
are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as a deferred
revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon
the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately
following the expiration of the lessee’s ability to recoup the payments. The Partnership’s deferred revenue (including affiliate)
consist of the following (in thousands):
Deferred revenue
Deferred revenue—affiliate
Total deferred revenue (including affiliate)
December 31,
2016
December 31,
2015
$
$
44,931
71,632
116,563
$
$
80,812
82,853
163,665
The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid
minimums as Coal royalty and other revenue (in thousands):
Coal royalty and other
Coal royalty and other—affiliates
Total coal royalty and other (including affiliates)
104
For the Year Ended December 31,
2016
2015
2014
$
$
49,284
15,307
64,591
$
$
3,451
12,038
15,489
$
$
6,659
—
6,659
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances
During the year ended December 31, 2016, the Partnership entered into agreements with certain lessees to either modify or
terminate existing coal related leases that resulted in the Partnership recognizing $40.5 million of deferred revenue as follows:
• An agreement that terminated a central Appalachia coal royalty lease and resulted in the lessee forfeiting the right to
recoup $26.2 million of minimum royalties previously paid to the Partnership. The Partnership agreed to transfer its coal mineral
rights that were subject to this former lease to the lessee. This terminated lease had no current or planned production and the
mineral rights transferred had zero net book value on the Partnership's consolidated Balance Sheets as of March 31, 2016. As a
result of this transaction, in April 2016 the Partnership recognized $26.2 million of revenue.
• Lease modifications, terminations and forfeitures of existing coal royalty and other leases resulted in lessee forfeiture of
rights to recoup previously paid minimum royalties and the reduction in lessee recoupment time. As a result of these modifications,
in the first and second quarters of 2016 the Partnership recognized $10.7 million of revenue.
• The Partnership recognized $3.6 million of revenue from various other coal and aggregates lease modifications,
terminations and forfeitures during the year ended December 31, 2016.
During the years ended December 31, 2015 and 2014, there was less than $0.1 million and $1.4 million of revenue recognized
from coal and aggregate lease modifications, terminations or forfeitures, respectively.
19. Subsequent Events
The following represents material events that have occurred subsequent to December 31, 2016 through the time of the
Partnership’s filing of its Annual Report on Form 10-K with the SEC:
Distribution Declared
On February 14, 2017, the Partnership paid a distribution of $0.45 per unit to unitholders of record on February 7, 2017.
Recapitalization Transactions
On March 2, 2017, the Partnership completed the following recapitalization transactions:
Issuance of Preferred Units and Warrants
NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred
Units") to Blackstone and 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 dividends 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"). 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.
The Preferred Units have a perpetual term, unless converted or redeemed as described below. The Preferred Units (including
any PIK Units) are convertible into common units at the election of the holders (1) after the fifth anniversary and prior to the eighth
anniversary of the issue date at a 7.5% discount to the volume weighted average trading price of our common units (the "VWAP")
for the 30 trading days immediately prior to the notice of conversion if the 30-day VWAP immediately prior to such notice is
greater than $51.00 (subject to a maximum of 33% of the Preferred Units per year) and (2) after the eighth anniversary of the issue
date at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Instead of issuing
common units pursuant to clause (1) of the preceding sentence, NRP has the option to redeem the Preferred Units proposed to be
converted for cash at a price equal to the Per Unit Purchase Price, plus the value of any accrued and unpaid distributions. To the
extent the holders of the Preferred Units have not elected to convert their Preferred Units by the twelfth anniversary of the issue
date, NRP has the right to force conversion of the Preferred Units into common units at a 10% discount to the VWAP for the 30
105
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
trading days immediately prior to the notice of conversion. In addition, NRP has the ability to redeem at any time (subject to
compliance with our debt agreements) all or any portion of the Preferred Units (including PIK Units) for cash at the agreed upon
per unit amount, which is calculated as the Per Unit Purchase Price multiplied by (i) prior to the third anniversary of the closing
date, 1.50, (ii) on or after the third anniversary of the closing date and prior to the fourth anniversary of the closing date, 1.70 and
(iii) on or after the fourth anniversary of the closing date, 1.85.
The terms of the Preferred Units contain certain restrictions on our ability to pay distributions on our common units. To the
extent that either (i) our consolidated Leverage Ratio (as defined in the Restated Partnership Agreement) is greater than 3.25x, or
(ii) the ratio of our Distributable Cash Flow 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, including:
•
the incurrence of new indebtedness, subject to certain exceptions;
• material changes to NRP’s business;
•
•
•
•
acquisitions and divestitures in excess of certain dollar thresholds;
amendments to material contracts resulting in a cash impact to NRP in excess of certain dollar thresholds;
settlement of any litigation or regulatory matter resulting in cash payments by NRP in excess of certain thresholds;
and
amendments to related party contracts outside of the ordinary course of business.
GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the Minimum
Preferred Unit Threshold (as defined below). The Preferred Purchaser Approval Rights are not transferrable without NRP's consent.
In addition, the Preferred Purchaser 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"). To the extent any Preferred Units that have converted into common units are still held by
the applicable Preferred Purchaser (or its affiliates), such common units will be deemed to represent a number of Preferred Units
based on the weighted average number of common units issued in each conversion and will count towards the Minimum Preferred
Unit Threshold.
The foregoing terms of the Preferred Units are reflected in our Fifth Amended and Restated Agreement of Limited Partnership,
dated as of March 2, 2017, which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference.
The terms of the Warrants are reflected in the Form of Warrant to Purchase Common Units filed as Exhibit 4.28 to this Annual
Report on Form 10-K, which is incorporated herein by reference.
At the closing, pursuant to a Board Representation and Observation Rights Agreement, the Preferred Purchasers received
certain board appointment and observation rights and appointed one director and one observer to the Board of Directors of GP
Natural Resource Partners LLC. For more information on these rights, see "Certain Relationships and Related Transactions, and
Director Independence—Board Representation and Observation Rights Agreement."
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. If the shelf registration statements are not effective by the
106
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
Opco Credit Facility Amendment
NRP entered into the Second Amendment to Opco’s Third Amended and Restated Credit Agreement to extend the term
thereof until April 2020, and reduced the commitments of the lenders to $180 million (from $210 million) effective at the closing
of the recapitalization transactions. Pursuant the Second Amendment, commitments under the Opco Credit Facility will be reduced
to $150 million at December 31, 2017 and further reduced to $100 million at December 31, 2018 through maturity in April 2020.
The amendment does not change the pricing grid or financial covenants under the Opco Credit Facility; 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. Other terms of the Second Amendment include
revisions to the mandatory prepayment provisions with respect to net cash proceeds received from certain asset sales and additional
limitations on the ability of Opco and its subsidiaries to make certain investments. The Second Amendment is filed as Exhibit
10.14 to this Annual Report on Form 10-K and is incorporated herein by reference.
Issuance of 2022 Notes; Exchange and Redemption of 2018 Notes
NRP and NRP Finance issued $346 million aggregate principal amount of 10.500% Senior Notes due 2022 to several holders
of its 2018 Notes. Of the $346 million of 2022 Notes issued, $241 million in aggregate principal amount were issued in exchange
for $241 million in aggregate principal amount of 2018 Notes, and $105 million of the 2022 Notes were issued to the holders in
exchange for cash. The 2022 Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 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.
NRP and NRP Finance have the option to redeem the 2022 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 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 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 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 Notes
may require us to purchase their 2022 Notes at a purchase price equal to 101% of the principal amount of the 2022 Notes, plus
accrued and unpaid interest, if any. The 2022 Notes purchased for cash were issued at a price of 98.75% (original issue discount
of 1.25%), and each holder exchanging 2018 Notes received a fee of 5.813% of the aggregate principal amount of all 2018 Notes
tendered for exchange by such holder, as well as all accrued and unpaid interest thereon.
The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing
the 2018 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 we have 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 the form of cash, unless, in each case, our 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 Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Notes rank equal in right of payment
to all existing and future senior unsecured debt of NRP and NRP Finance, including the remaining outstanding 2018 Notes, and
senior in right of payment to any of NRP's subordinated debt. The 2022 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
107
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the
Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiaries guarantee the 2022 Notes.
The terms of the 2022 Notes are more fully described in the 2022 Indenture, which is filed as Exhibit 4.24 to this Annual
Report on Form 10-K and incorporated herein by reference.
NRP entered into a registration rights agreement (the "Notes Registration Rights Agreement") with the holders of the 2022
Notes, pursuant to which we and NRP Finance agreed to file a registration statement with the Securities and Exchange Commission
for the benefit of the holders of the 2022 Notes so that such holders can exchange the 2022 Notes for exchange securities that have
substantially identical terms as the 2022 Notes. NRP and NRP Finance agreed to use commercially reasonable efforts to cause the
exchange to be completed within 180 days after the closing and will be required to pay additional interest, as specified in the Notes
Registration Rights Agreement, if NRP fails to comply with its obligations to register the 2022 Notes within the specified time
periods.
NRP expects to redeem $90 million in aggregate principal amount of the 2018 Notes at a redemption price of 104.563%,
and pay all accrued and unpaid interest thereon, in April 2017. In addition, NRP is required to redeem any and all remaining
outstanding 2018 Notes (and pay accrued and unpaid interest thereon) within 60 days after October 1, 2017.
108
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
As discussed in Note 3. Discontinued Operations, the Partnership sold its non-operated oil and gas working interest assets
in July 2016 and exited this business. The Partnership prepared the following oil and gas information in accordance with the
authoritative guidance for oil and gas extractive activities for the years ended December 31, 2015 and 2014.
Capitalized Costs for the year ended December 31, 2015 (in thousands):
Proven properties
Unproven properties
Total property, plant, and equipment
Accumulated depreciation, depletion, and amortization
Net capitalized costs
Costs incurred for property acquisitions, exploration, and development (in thousands):
$
$
199,404
—
199,404
(60,542)
138,862
Property acquisitions
Proven properties
Unproven properties
Development
Total
Results of Operations for Producing Activities (in thousands):
Production revenue
Royalty and overriding royalty revenue (1)
Total oil and gas related revenue
Operating costs and expense:
Depreciation, depletion and amortization
Property, franchise and other taxes
Production costs
Impairment of oil and gas properties
Total operating costs and expense
Total income from operations
For the Years Ended
December 31,
2015
2014
$
$
— $
—
29,080
29,080
$
298,627
40,800
5,340
344,767
For the Years Ended
December 31,
2015
2014
$
49,201
$
4,364
53,565
40,772
5,210
12,871
367,576
426,429
(372,864) $
$
48,834
10,732
59,566
23,936
5,529
12,544
—
42,009
17,557
(1) Includes $0.4 million and $1.9 million for the years ended December 31, 2015 and 2014, respectively of nonproduction
revenues including lease bonus payments
Estimated Proved Reserves
Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can
be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under
existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the
right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves,
the term "reasonable certainty" implies a high degree of confidence that the quantities of crude oil, natural gas liquids and/or natural
gas actually recovered will equal or exceed the estimate. The Partnership estimated proved reserves as of December 31, 2015 and
2014 were prepared by a third party independent reserve engineer. To achieve reasonable certainty, the third party engineer employed
technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data
109
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
used in the estimation of the Partnership’s proved reserves include, but are not limited to, well logs, geologic maps including
isopach and structure maps, analogy and statistical analysis, and available downhole and production data and well test data. The
third party engineer prepared its report covering properties representing 100% of the Partnership’s estimated proved reserves as
of December 31 2015 and 2014. Prices were calculated using the unweighted average of the first-day-of-the-month pricing for the
twelve months ended December 31, 2015 and 2014. These prices were then adjusted for transportation and other costs. There can
be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are
numerous uncertainties inherent in estimating reserves and related information and different reserve engineers often arrive at
different estimates for the same properties.
The following table shows our estimated domestic proved reserves and reserve additions and revisions:
December 31, 2014
Revisions of previous estimates
Extensions, discoveries and other additions
Sales of properties
Production
December 31, 2015 (1)
Proved developed reserves as of December 31, 2015
Proved undeveloped reserves as of December 31, 2015
Crude
Oil
(MBbl)
NGLs
(MBbl)
Natural
Gas
(MMcf)(2)
Total
Proved
Reserves
(MBoe)(3)
9,983
(1,451)
776
(98)
(1,136)
8,074
7,862
212
1,229
89
60
—
(156)
1,222
1,196
26
14,370
701
541
(62)
(2,226)
13,324
13,157
167
13,607
(1,244)
926
(108)
(1,663)
11,518
11,251
267
(1) Includes reserves attributable to the Partnership's 51% member interest in BRP LLC.
(2) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content
equivalency and not a price or revenue equivalency.
(3) Includes 10,063MBoe of estimated proved reserves attributable to the Partnership’s non-operated working interests in
oil and natural gas properties in the Williston Basin, approximately 3% of which were proved undeveloped reserves.
The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows
for the year ended December 31, 2015 (in thousands):
Future cash inflows
Less related future:
Production costs
Development and abandonment costs
Future net cash flows before 10% discount
Discount to present value at a 10% annual rate
Total standardized measure of discounted net cash flows
$
364,352
(164,649)
(7,826)
191,877
(75,524)
116,353
$
110
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
The table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved
oil and gas reserves during the year ended December 31, 2015 (in thousands):
$
305,197
(188,946)
(11,750)
(12,202)
29,080
11,928
(3,851)
31,795
(35,112)
(9,786)
(188,844)
116,353
Beginning of the period
Revisions to previous estimates:
Changes in prices and costs
Changes in quantities
Changes in future development costs
Previously estimated development costs incurred during the period
Additions to proved reserves from extensions, discoveries and improved recovery, less related costs
Purchases and sales of reserves in place, net
Accretion of discount
Sales of oil and gas, net of production costs
Production timing and other
Net increase (decrease)
End of period
$
111
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following table summarizes quarterly financial data for 2016 and 2015 (in thousands, except per unit data):
2016
Revenues (including affiliates)
Gains on asset sales (2)
Depreciation, depletion and amortization
(including affiliates)
Asset impairment
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
Net income from continuing operations per limited partner
unit
Net income (loss) from discontinued operations per limited
partner unit
First
Quarter (1)
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
2016
$
73,902
21,925
$ 119,317
(1,071)
$
91,448
$
86,311
$ 370,978
6,426
1,801
29,081
10,502
1,893
48,991
26,351
(2,924)
11,176
91
70,741
48,633
(2,187)
12,831
5,697
38,907
16,419
7,112
11,763
9,245
27,106
3,811
(323)
46,272
16,926
185,745
95,214
1,678
$
$
2.11
$
3.90
$
1.32
(0.23) $
(0.18) $
0.57
$
$
0.31
$
7.65
(0.03) $
0.13
Weighted average number of common units outstanding
12,232
12,232
12,232
12,232
12,232
2015
Revenues (including affiliates)
Gains on asset sales
Depreciation, depletion and amortization
(including affiliates)
Asset impairment (4)
Income (loss) from operations
Net income (loss) from continuing operations
Net income (loss) from discontinued operations
First
Quarter (1)
Second
Quarter
Third
Quarter
Fourth
Quarter (3)
Total
2015
$
94,447
$ 120,228
$ 112,199
1,615
3,455
1,833
$ 105,874
(3)
$ 432,748
6,900
11,514
—
46,499
24,379
(6,890)
19,077
3,803
58,324
36,389
(3,811)
16,437
361,703
(307,831)
(330,736)
(269,265)
13,888
19,039
32,581
9,797
(31,583)
60,916
384,545
(170,427)
(260,171)
(311,549)
Net income (loss) from continuing operations per limited
partner unit
Net income (loss) from discontinued operations per limited
partner unit
Weighted average number of common units outstanding
$
$
1.95
$
2.82
$
(26.34) $
0.78
$
(20.78)
(0.55) $
(0.31) $
12,232
12,232
(21.57) $
12,232
(2.53) $
12,232
(24.97)
12,232
(1) As a result of the sale of its non-operated oil and gas working interest business effective April 1, 2016, the Partnership
classified the operating results and cash flows of its non-operated oil and gas working interest assets as discontinued
operations in its consolidated statements of comprehensive income subsequent to the filing of the First Quarter 2016 Form
10-Q. See below for a reconciliation to the amounts reported in the First Quarter 2016 Form 10-Q.
(2) During the first quarter of 2016 the Partnership sold oil and gas royalty and aggregates royalty assets for a cumulative gain
of $21.9 million. During the third quarter of 2016 the Partnership sold assets in multiple sale transactions for a net gain of
$6.4 million primarily related to eminent domain transactions with governmental agencies.
(3) As a result of the sale of its non-operated oil and gas working interest business effective April 1, 2016, the Partnership
classified the operating results and cash flows of its non-operated oil and gas working interest assets as discontinued
operations in its consolidated statements of comprehensive income subsequent to the filing of the 2015 Form 10-K where
this quarter's results were previously reported. See below for a reconciliation to the amounts reported in the 2015 Form
10-K.
112
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
(4) See Note 9. Mineral Rights for asset impairment discussion.
The following table reconciles previously reported quarterly information to the quarterly financial data disclosed above
(in thousands, except per unit data):
As Previously
Reported
Reclassified to
Discontinued
Operations
Revised
First Quarter 2016
Revenues
Gains on asset sales
Depreciation, depletion and amortization
Asset impairment
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
Net income from continuing operations per limited partner unit
Net income (loss) from discontinued operations per limited partner unit
Weighted average number of common units outstanding
First Quarter 2015
Revenues
Gains on asset sales
Depreciation, depletion and amortization
Asset impairment
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
$
$
$
80,826
21,925
14,743
2,030
47,156
23,427
—
1.88
$
$
— $
12,232
$
107,611
$
2,066
25,392
—
40,417
17,489
—
Net income from continuing operations per limited partner unit
Net income (loss) from discontinued operations per limited partner unit
Weighted average number of common units outstanding
$
$
1.40
$
— $
12,232
(6,924) $
—
(4,241)
(137)
1,835
2,924
(2,924)
$
0.23
(0.23) $
(13,164) $
(451)
(13,878)
—
6,082
6,890
(6,890)
0.55
$
(0.55) $
73,902
21,925
10,502
1,893
48,991
26,351
(2,924)
2.11
(0.23)
12,232
94,447
1,615
11,514
—
46,499
24,379
(6,890)
1.95
(0.55)
12,232
Fourth Quarter 2015
Revenues
Gains on asset sales
Depreciation, depletion and amortization
Asset impairment
Income from operations
Net income from continuing operations
Net income (loss) from discontinued operations
Net income from continuing operations per limited partner
unit
Net income (loss) from discontinued operations per limited
partner unit
$
$
$
Weighted average number of common units outstanding
12,232
113
As Reported
Presentation
Reclassification
Reclassified to
Discontinued
Operations
As Revised
$
116,063
—
18,152
50,953
2,042
(21,786)
—
$
3
(3)
—
—
—
—
—
(10,192) $
—
(4,264)
(31,914)
30,539
31,583
(31,583)
105,874
(3)
13,888
19,039
32,581
9,797
(31,583)
(1.75) $
— $
2.53
$
0.78
— $
— $
(2.53) $
(2.53)
12,232
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, 2016. 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, 2016 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, 2016
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, our management concluded that our internal control
over financial reporting was effective as of December 31, 2016. 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.
Report of Independent Registered Public Accounting Firm
The Partners of Natural Resource Partners L.P.
We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2016, 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). Natural Resource Partners L.P.’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 company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). 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.
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
114
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.
In our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2016 and 2015, and the related consolidated
statements of comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended
December 31, 2016 and our report dated March 6, 2017 expressed an unqualified opinion there thereon.
/s/ Ernst & Young LLP
Houston, Texas
March 6, 2017
ITEM 9B. OTHER INFORMATION
None.
115
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. Unless otherwise noted below, the individuals served as officers or directors of the partnership since the initial public offering.
Subject to the Investor Rights Agreement with Adena Minerals, LLC, and the Board Representation and Observation Rights
Agreement with Blackstone and GoldenTree. Mr. Robertson is entitled to nominate eleven directors to the Board of Directors of
GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be
independent, to Adena Minerals, and the right to nominate one director to Blackstone.
Name
Corbin J. Robertson, Jr.
Wyatt L. Hogan
Craig W. Nunez
Christopher J. Zolas
Kevin J. Craig
Kathy H. Roberts
Kathryn S. Wilson
Gregory F. Wooten
Robert T. Blakely
Russell D. Gordy
L. G. (Trey) Jackson III
Robert B. Karn III
Jasvinder S. Khaira
S. Reed Morian
Richard A. Navarre
Corbin J. Robertson, III
Stephen P. Smith
Leo A. Vecellio, Jr.
Age
Position with the General
Partner
69 Chairman of the Board and Chief Executive Officer
45 President and Chief Operating Officer
55 Chief Financial Officer and Treasurer
42 Chief Accounting Officer
48 Executive Vice President, Coal
65 Vice President, Investor Relations
42 Vice President, General Counsel and Secretary
61 Vice President, Chief Engineer
75 Director
66 Director
41 Director
75 Director
35 Director
71 Director
56 Director
46 Director
56 Director
70 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.
Wyatt L. Hogan has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since March
2015. From September 2014 through February 2015, Mr. Hogan served as President of GP Natural Resource Partners LLC.
Mr. Hogan was Executive Vice President of GP Natural Resource Partners from December 2013 through August 2014 and Vice
President, General Counsel and Secretary of GP Natural Resource Partners from May 2003 to December 2013. Mr. Hogan joined
NRP in 2003 from Vinson & Elkins L.L.P., where he practiced corporate and securities law from August 2000 through April 2003.
Mr. Hogan also serves as Executive Vice President of Quintana Minerals Corporation, New Gauley Coal Corporation, the general
116
partner of Western Pocahontas Properties Limited Partnership and the general partner of Great Northern Properties Limited
Partnership, and from 2003 to October 2013, Mr. Hogan served as General Counsel and Secretary of those entities. He is also a
member of the Board of Directors of Quintana Minerals Corporation and represents NRP as one of its appointees to the Board of
Managers of Ciner Wyoming LLC. Mr. Hogan also serves as a member of the Board of the National Mining Association and the
American Coalition for Clean Coal Electricity. Mr. Hogan has been involved in numerous charitable organizations and currently
serves on the Boards of Kids' Meals, Inc. and the Kinkaid Investment Foundation and serves as Chairman of the Board of the
Kinkaid Alumni Association.
Craig W. Nunez has served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC since January
2015. 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 Accounting Officer of GP Natural Resource Partners since March 2015. Prior to
joining NRP, Mr. Zolas served as Director of Financial Reporting at Cheniere Energy, Inc., a publicly traded energy company,
where he performed financial statement preparation and analysis, technical accounting and SEC reporting for five separate SEC
registrants, including a master limited partnership. Mr. Zolas joined Cheniere Energy, Inc. in 2007 as Manager of SEC Reporting
and Technical Accounting and was promoted to Director in 2009. Prior to joining Cheniere Energy, Inc., Mr. Zolas worked in
public accounting with KPMG LLP from 2002 to 2007.
Kevin J. Craig has served as Executive Vice President, Coal of GP Natural Resource Partners since September 2014. Mr.
Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr. Craig also represents
NRP as one of its appointees to the Board of Managers of Ciner Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX
Transportation, where he served as Terminal Manager for the West Virginia Coalfields. He has extensive marketing, finance and
operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates having
been elected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate
Craig served as Chairman of the Committee on Energy. Mr. Craig did not seek re-election in 2014 and his term ended January
2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig has served as the Chairman of the
Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber
of Commerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He is involved in numerous
state coal associations and serves as a member of the Board of Directors of BrickStreet Mutual Insurance Company.
Kathy H. Roberts is Vice President, Investor Relations of GP Natural Resource Partners LLC. Ms. Roberts joined NRP in
July 2002. She was the Principal of IR Consulting Associates from 2001 to July 2002 and from 1980 through 2000 held various
financial and investor relations positions with Santa Fe Energy Resources, most recently as Vice President-Public Affairs. She is
a Certified Public Accountant. Ms. Roberts currently serves on the Board of Directors of the Master Limited Partnership Association
and has served on the local board of directors of the National Investor Relations Institute. She has also served on the Executive
Committee and as a National Vice President of the Institute of Management Accountants.
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 Quintana Minerals Corporation, New Gauley Coal
Corporation, the general partner of Western Pocahontas Properties Limited Partnership, and the general partner of Great Northern
Properties Limited Partnership. Ms. Wilson also represents NRP as one of its appointees to the Board of Managers of Ciner
Wyoming LLC. 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. Ms. Wilson also represents NRP as one of its appointees to the Board of Managers of Ciner Wyoming
LLC.
117
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.
Robert T. Blakely joined the Board of Directors of GP Natural Resource Partners LLC in January 2003. Mr. Blakely has
extensive public company experience having served as Executive Vice President and Chief Financial Officer for several companies.
From January 2006 until August 2007, he served as Executive Vice President and Chief Financial Officer of Fannie Mae, and from
August 2007 to January 2008 as an Executive Vice President at Fannie Mae. From mid-2003 through January 2006, he was
Executive Vice President and Chief Financial Officer of MCI, Inc. He previously served as Executive Vice President and Chief
Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco,
Inc. from 1981 until 1999 as well as a Managing Director at Morgan Stanley. He served until December 31, 2011 as a Trustee of
the Financial Accounting Foundation and is a trustee emeritus of Cornell University. He has served on the Board of Westlake
Chemical Corporation since August 2004. In 2009, Mr. Blakely joined the Boards of Directors of Greenhill & Co. and Ally Financial
(formerly GMAC, Inc.), where he serves as Chairman of the Audit Committee.
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.
L. G. (Trey) Jackson III joined the Board of Directors of GP Natural Resource Partners LLC in April 2016. Mr. Jackson
brings financial and coal industry experience to the Board of Directors. Mr. Jackson is currently the Managing Director of the
Cline Group, a group of companies affiliated with Christopher Cline, having served in that capacity since March 2011, where he
has responsibility for mergers and acquisitions, deal structuring and certain other commercial activities. Also during this time,
from June 2013 until August 2015, Mr. Jackson served as the President of Convent Marine Terminal. Prior to joining Mr. Cline’s
management group, Mr. Jackson served in various capacities at two energy private equity firms and a boutique investment bank.
Mr. Jackson also serves on the Board of Directors of Material Sciences Corp.
Robert B. Karn III joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Karn brings extensive
financial and coal industry experience to the Board of Directors. He currently is a consultant and serves on the Board of Directors
of various entities. He was the partner in charge of the coal mining practice worldwide for Arthur Andersen from 1981 until his
retirement in 1998. He retired as Managing Partner of the St. Louis office’s Financial and Economic Consulting Practice. Mr. Karn
is a Certified Public Accountant, Certified Fraud Examiner and has served as president of numerous organizations. He also currently
serves on the Board of Directors of Peabody Energy Corporation, Kennedy Capital Management, Inc. and the Board of Trustees
of numerous publicly listed closed-end, mutual and exchange traded funds of the Guggenheim family of funds.
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. Mr. Khaira joined Blackstone as a member of its Private Equity Group
in 2004. 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
118
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.
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
of the Audit Committee, 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 a member of the Board of Directors of the Foreign Policy Association and 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 and LKCM Headwater Investments I, L.P., a private equity fund, since 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 the general partner of Genesis Energy L.P., a publicly traded master limited partnership, as well as Corsa
Coal Corp, Buckhorn Energy Services 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 and Chief Accounting Officer of the general partner of Columbia Pipeline Partners L.P. from December
2014 and as a Director from September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and
Chief Financial Officer of Columbia Pipeline Group. Mr. Smith served as Executive Vice President and Chief Financial Officer
for NiSource, Inc. from June 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. From
November 2000 to January 2003, Mr. Smith served as President and Chief Operating Officer - Corporate Services for NiSource
Inc. Prior to joining NiSource, Mr. Smith served as Deputy Chief Financial Officer for Columbia Energy Group from November
1999 to November 2000 and Chief Financial Officer for Columbia Gas Transmission Corporation and Columbia Gulf Transmission
Company from 1996 to 1999.
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.
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Corporate Governance
Board Meetings and Executive Sessions
The Board met 16 times in 2016. During 2016, our non-management directors met in executive session several times. The
presiding director was Mr. Blakely, 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 2016. Mr. Blakely 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.
In April 2016, Donald R. Holcomb resigned from the Board of Directors of GP Natural Resource Partners LLC, and L.G.
(Trey) Jackson, III was appointed to the Board. In March 2017, Jasvinder Khaira was appointed to the Board by Blackstone.
Independence of Directors
The Board of Directors has affirmatively determined that Messrs. Blakely, Gordy, Karn, 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. Although we had a majority of independent directors in 2016, because we are a limited
partnership as defined in Section 303A of the NYSE’s listing standards, we are not required to do so. The Board has an Audit
Committee, a Compensation, Nominating and Governance Committee, and a Conflicts Committee, each of which is staffed solely
by independent directors.
Audit Committee
Our Audit Committee is comprised of Robert B. Karn III, who serves as chairman, Robert T. Blakely, Richard A. Navarre
and Stephen P. Smith. Mr. Karn, Mr. Blakely, Mr. Navarre and Mr. Smith are "Audit Committee Financial Experts" as determined
pursuant to Item 407 of Regulation S-K. During 2016, the Audit Committee met seven times.
Report of the Audit Committee
Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the
independence and experience requirements of the New York Stock Exchange. The Audit Committee has adopted, and annually
reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements. The Audit
Committee Charter is available on our website at www.nrplp.com and is available in print upon request.
During 2016, 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, 2016 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
120
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 2016 was compatible with the auditors’ independence.
In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Audit Committee reviews
our Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K prior to filing with the Securities and Exchange
Commission. In 2016, 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, 2016, for filing with the Securities and Exchange Commission.
Robert B. Karn III, Chairman
Robert T. Blakely
Richard A. Navarre
Stephen P. Smith
Compensation, Nominating and Governance Committee
Executive officer compensation is administered by the CNG Committee, which is comprised of four members. Mr. Blakely,
the Chairman, has served on the CNG Committee since 2003. Mr. Karn has served on the CNG Committee since 2002. Mr. Vecellio
joined the Committee in 2007, and Mr. Gordy joined the CNG Committee in 2013. 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 2016, the CNG Committee met four times. Our Board of Directors appoints the CNG Committee and delegates to
the CNG Committee responsibility for:
•
•
•
reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates
to our business;
reviewing and recommending the annual and long-term incentive plans in which our executive officers participate; and
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 2015, and we believe that 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 2016.
121
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 and the amendments are also filed with the SEC and are 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 2016, 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.
122
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. We have no employees, other than at the VantaCore operations, and our executive officers based in
Houston, Texas are employed by Quintana Minerals Corporation and our executive officers based in Huntington, West Virginia
are employed by Western Pocahontas Properties Limited Partnership, both of which are our affiliates. For a more detailed description
of our structure, see "Item 1. Business—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.
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 through a difficult market cycle. Although we historically have not tied our compensation to achievement
of specific financial targets or fixed performance criteria, we have reevaluated that strategy in light of current market conditions.
See "—Evaluation of 2016 Performance; Components of Compensation-Long-Term Incentive Compensation-2016 Cash Long-
Term Incentive Plan" below.
The 2016 compensation for executive officers consisted of four primary components:
base salaries;
annual cash incentive awards, including cash payments made by our general partner based on the cash distributions it
receives from the common units that it owns (which we refer to herein as "GP Bonus Awards");
long-term equity and cash incentive compensation; and
perquisites and other benefits.
•
•
•
•
In December 2015, our CNG Committee reviewed the performance of the executive officers and the amount of time expected
to be spent by each NRP officer on NRP business, and determined the salaries for each officer for 2016. All of our named executive
officers, other than Corbin J. Robertson, Jr., our Chairman and Chief Executive Officer and Kathryn S. Wilson, our Vice President,
General Counsel and Secretary, spent 100% of their time on NRP matters during 2016, and NRP bears the cost of their time.
Mr. Robertson has historically spent approximately 50% of his time on NRP matters. Mr. Robertson does not receive a salary or
an annual bonus in his capacity as Chief Executive Officer. Rather, Mr. Robertson has historically been compensated exclusively
through long-term incentive awards and through GP Bonus Awards. Mr. Robertson also directly or indirectly owns in excess of
20% of the outstanding common units of NRP, and thus his interests are directly aligned with our unitholders. In 2016, Ms. Wilson
spent approximately 94% of her time on NRP matters and the rest of her time on private Robertson family owned company matters,
and her time has been allocated to NRP accordingly.
Historically, in February of each year, the CNG Committee has approved the year-end bonuses 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. Because we are a partnership,
tax and accounting conventions make it more costly for us to issue additional common units or options as incentive compensation.
Consequently, we have no outstanding options or restricted units and currently have no plans to issue options or restricted units
in the future. Instead, prior to 2016, we issued phantom units, coupled with tandem distribution equivalent rights ("DERs"), to
our executive officers that are 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 vest four years from the date of grant. In past years, these awards have
served to align the executive officers’ interests with those of our unitholders.
123
During 2015, given the sharp decline in NRP’s unit price, the Board of Directors recognized that the value of the executive
officers’ phantom unit awards and the decreased GP Bonus Awards no longer provided long-term incentive or retention value to
management. Accordingly, the Board authorized and directed the CNG Committee to begin a review of options for a new long-
term incentive program for NRP management to be adopted in 2016. Upon the conclusion of this review, in February 2016, the
CNG Committee elected not to award additional phantom units under the long-term incentive plan and instead adopted a new cash
long-term incentive plan and recommended the new plan and forms of award agreements thereunder to the Board for approval.
The Board approved the new plan and awards in February 2016 and approved awards to officers under the plan in March 2016.
In March 2017, the Board determined that the conditions to the vesting of the performance awards had been met as a result of the
completion of the 2017 recapitalization transactions described elsewhere in this Annual Report on Form 10-K. See "—Evaluation
of 2016 Performance; Components of Compensation-Long-Term Incentive Compensation-2016 Cash Long-Term Incentive Plan"
below.
In light of the recently completed recapitalization transactions, the CNG Committee is evaluating a new long-term incentive
program that best reflects the current outlook for NRP. Accordingly, no long-term incentive awards have yet been made during
2017. The CNG Committee and the Board may determine to award additional cash incentive awards, phantom unit awards or
other forms of long-term incentive compensation during 2017.
Role of Compensation Experts
Historically, the CNG Committee periodically has utilized consultants to get a basic sense of the market, but has considered
the advice of the consultant as only one of many factors among the other items discussed in this compensation discussion and
analysis. For a more detailed description of the CNG Committee and its responsibilities, see "Item 10. Directors and Executive
Officers of the Managing General Partner and Corporate Governance" in this Annual Report on Form 10-K.
During 2015, at the direction of the Board, the CNG Committee retained Meridian Compensation Partners ("Meridian") to
advise on a new long-term incentive strategy to be implemented in 2016 in order to incentivize and retain management in light of
the significant decrease in phantom unit award value and GP Bonus Awards. See "—Evaluation of 2016 Performance; Components
of Compensation-Long-Term Incentive Compensation-2016 Cash Long-Term Incentive Plan" below. In selecting Meridian as its
compensation consultant, the CNG Committee assessed the independence of Meridian pursuant to SEC rules and considered,
among other things, whether Meridian provides any other services to NRP, the policies of Meridian that are designed to prevent
any conflict of interest between Meridian, the CNG Committee and NRP, any personal or business relationship between Meridian
and a member of the CNG Committee or one of NRP’s executive officers and whether Meridian owned any of NRP’s common
units. In addition to the foregoing, the CNG Committee received documentation from Meridian addressing the firm’s independence.
Meridian was engaged directly by the CNG Committee, reported exclusively to the CNG Committee and does not provide any
additional services to NRP. The CNG Committee concluded that Meridian is independent and did not have any conflicts of interest.
While management did cooperate with Meridian in collecting data with respect to NRP’s compensation programs, the CNG
Committee determined that management had not attempted to influence Meridian’s review or recommendations.
Role of Our Executive Officers in the Compensation Process
Mr. Hogan, our President and Chief Operating Officer, provided Mr. Robertson with recommendations relating to the
executive officers other than himself in connection with the evaluation of the 2016 compensation programs. Mr. Robertson
considered those recommendations and provided the CNG Committee with recommendations for all of the executive officers other
than himself. Mr. Robertson relied on his personal experience in setting compensation over a number of years in determining the
appropriate amounts for each employee, and considered each of the factors described elsewhere in this compensation discussion
and analysis. Mr. Robertson and Mr. Hogan attended the CNG Committee meetings at which the Committee deliberated and
approved the compensation, but were excused from the meetings when the CNG Committee discussed their compensation. Mr.
Nunez and Ms. Wilson also participated in the meetings with Meridian and the CNG Committee with respect to the design and
implementation of the 2016 Cash Long-Term Incentive Plan.
124
Evaluation of 2016 Performance; Components of Compensation
2016 Performance
Our Board of Directors considers Adjusted EBITDA, distributable cash flow and overall leverage to be the critical measures
in evaluating NRP’s performance. Despite the continued depressed coal and oil and gas markets in 2016, we recorded Adjusted
EBITDA in 2016 of $255.5 million, which was essentially flat compared to our Adjusted EBITDA in 2015, and distributable cash
flow of $271.4 million, which increased from $176.6 million in 2015 primarily as a result of cash proceeds from asset sales in
2016.
Other factors considered by the CNG Committee in determining total management compensation for 2016 included:
•
•
•
•
•
•
the sale of approximately $181 million of assets during 2016, including $116.1 million of oil and gas working
interests and royalty interests that marked NRP’s strategic exit from the non-operated oil and gas working interest
business;
the permanent reduction in NRP’s debt of approximately $248 million during 2016;
the extension in 2016 of the maturity date under Opco’s revolving credit facility to June 2018;
the increase in the trading price of NRP’s common units of over 300% during 2016;
overall cost reductions; and
additional revenue of $40 million recognized in connection with lease amendments in the coal segment.
Base Salaries
With the exception of Mr. Robertson, who, as described above, does not receive a salary for his services as Chief Executive
Officer, our executive officers are paid an annual base salary by Quintana Minerals Corporation ("Quintana") or Western Pocahontas
Properties Limited Partnership ("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 2016, at the December 2015 meeting, the CNG Committee considered
the financial performance of NRP for the nine months ended September 30, 2015 as well as the projected financial performance
of NRP for the fourth quarter of 2015 and for the year ending December 31, 2016. The CNG Committee also considered the
individual performance of each member of the executive management team during 2015 and the changes to the management team
that became effective during the year. Based on its review, the CNG Committee approved the salaries disclosed in the Summary
Compensation Table below.
Annual Cash Incentive Awards
Each named executive officer participated in two cash incentive programs in 2016, with the exception of Mr. Robertson who
did not participate in the cash bonus program. The first program is a discretionary cash bonus award approved in February 2017
by the CNG Committee based on similar criteria used to evaluate the annual base salaries. The bonuses awarded with respect to
2016 under this program are disclosed in the Summary Compensation Table under the Bonus column. As with the base salaries,
there are no formulas or specific performance targets related to these awards. The bonuses for Mr. Hogan, Mr. Nunez, Ms. Wilson
and Mr. Zolas were increased over the prior year in part to offset the declines in other components of their compensation and in
recognition of their contributions to NRP.
Under the second cash incentive program (the GP Bonus Award program), our general partner has set aside the cash
distributions it receives on an annual basis with respect to distributions on NRP’s common units held by our general partner for
awards to our executive officers, including Mr. Robertson. Although Mr. Robertson has the sole discretion to determine the GP
Bonus Awards allocated to each executive officer, including himself, the cash awards that our officers receive under this plan are
125
reviewed by the CNG Committee and taken into account when making determinations with respect to salaries, bonuses and long-
term incentive awards. Unlike the discretionary cash bonus award described above, the GP Bonus Awards are paid by the general
partner and not reimbursed by NRP. However, because the GP Bonus Awards represent compensation to executive officers related
to services provided to NRP, they are recorded by NRP as general and administrative expenses and equity contributions from the
general partner. Prior to 2015, we did not record the GP Bonus Awards cash compensation paid by the general partner as an
expense.
The amounts received by the named executive officers under the GP Bonus Award program were significantly lower for
2016 as compared to 2015 due to the 87% reduction in the per unit distribution paid by NRP during the calendar year ended
December 31, 2015. This decrease resulted in a decreased overall amount allocated to the executive officers. Mr. Robertson
determined to allocate the GP Bonus Awards equally among our executive officers.
Long-Term Incentive Compensation
At the time of our initial public offering, we adopted the Natural Resource Partners Long-Term Incentive Plan for our directors
and all the employees who perform services for NRP, including the executive officers. Historically, we considered long-term
equity-based incentive compensation to be the most important element of our compensation program for executive officers because
we believed that these awards kept our officers focused on the growth of NRP, particularly the sustainability and long-term growth
of quarterly distributions and their impact on our unit price, over an extended time horizon.
Our CNG Committee has historically approved annual awards of phantom units that vest four years from the date of grant.
The amounts included in the compensation table reflect the grant date fair value of the unit awards determined in accordance with
FASB stock compensation authoritative guidance. NRP bears 100% of the costs of the phantom units. We structured the phantom
unit awards so that our executive officers and directors directly benefited along with our unitholders when our unit price increases,
and experienced reductions in the value of their incentive awards when our unit price declined. Similarly, because the awards are
forfeited by the executives upon termination of employment in most instances, the long-term vesting component of these awards
encouraged our senior executives and employees to remain with NRP over an extended period of time, thereby ensuring continuity
in our management team. Consistent with this approach, we included DERs as a possible award to be granted under the plan. The
DERs are contingent rights, granted in tandem with phantom units, to receive upon vesting of the related phantom units an amount
in cash equal to the cash distributions made by NRP with respect to the common units during the period in which the phantom
units are outstanding.
As noted below, in light of then existing market conditions, the relative low value of NRP’s common units and the strategic
plan to dedicate all free cash flow towards reducing NRP’s leverage, the CNG Committee determined that the phantom units and
DERs awarded under the Long-Term Incentive Plan no longer held retentive value for NRP’s management team. As a result, the
CNG Committee recommended, and the Board approved, the 2016 Cash Long-Term Incentive Plan described below.
2016 Cash Long-Term Incentive Plan
In February 2016, the CNG Committee adopted a new cash-based long-term incentive plan and recommended the new plan
and awards thereunder to the non-management members of the Board for approval. The Board approved the new plan and the
forms of long-term incentive award agreements in February 2016. Two types of cash incentive awards were made to the executive
officers in March 2016: (1) time vesting awards, 50% of which vested in February 2017 and 50% of which will vest in February
2018, and (2) performance-based awards that provide that such awards vest 50% upon the repayment, refinancing or rollover of
the Opco revolving credit facility that matures in April 2018 and 50% upon the repayment, refinancing or rollover of NRP’s 9.125%
Senior Notes due October 2018, in each case as determined by the Board and depending upon the continued employment of the
applicable executive officer. The performance awards also provide that up to an additional 100% of the amount of the performance-
based awards may be awarded to the executive officers in the sole discretion of the Board after considering additional performance
criteria including, but not limited to, NRP’s common unit price, projected EBITDA, and leverage ratio. The awards made in March
2016 to the named executive officers under the cash long-term incentive plan are as follows:
126
2016 Cash Incentive Awards
Performance
Award
Grant Amount
Time Vesting
Award
Grant Amount (1)
Total
Award
Grant Amount
Total
Maximum
Payout Amount
Corbin J. Robertson, Jr. - Chairman and Chief Executive
Officer
Wyatt L. Hogan - President and Chief Operating Officer
Craig W. Nunez - Chief Financial Officer and Treasurer
Kathryn S. Wilson - Vice President, General Counsel and
Secretary
Christopher J. Zolas - Chief Accounting Officer
$
$
1,500,000
750,000
562,500
450,000
150,000
500,000
250,000
187,500
150,000
150,000
$
$
2,000,000
1,000,000
750,000
600,000
300,000
3,500,000
1,750,000
1,312,500
1,050,000
450,000
(1) One-half of each time vesting award granted in 2016 vested in 2017.
Following the completion of the March 2017 recapitalization transactions, on March 3, 2017, the Board determined that
both vesting conditions of the performance awards had been met and therefore the target performance award grant amounts would
be awarded to each executive officer. In addition, following consideration of additional performance criteria including, but not
limited to: (1) the performance of NRP’s common units over the past twelve months and subsequent to the announcement of the
transactions; (2) the 2016 and projected 2017 EBITDA for NRP; and (3) the current and projected leverage ratios for NRP and its
subsidiaries, the Board determined to award an additional 100% of the amount of the performance-based awards to the executive
officers. The amounts that will be paid to the named executive officers will be equal to 200% of the performance award grant
amounts shown in the table above. These amounts will be paid will be paid to the officers within 30 days of the date of the Board’s
determination.
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.
Quintana and Western Pocahontas also maintain tax-qualified 401(k) and defined contribution retirement plans. Quintana
matches 100% of the first 4.5% of the employee contributions under the 401(k) plan and Western Pocahontas matches the employee
contributions at a level of 100% of the first 3% of the contribution and 50% of the next 3% of the contribution. In addition, each
company contributes 1/12 of each employee’s base salary to the defined contribution retirement plan on an annual basis. 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
We do not have any policy guidelines that require specified ownership of our common units by our directors or executive
officers or unit retention guidelines applicable to equity-based awards granted to directors or executive officers. As of December 31,
2016, our named executive officers held 21,540 phantom units that have been granted as compensation. In addition, Mr. Robertson
directly or indirectly owns in excess of 20% of the outstanding units of NRP.
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.
Tax Implications of Executive Compensation
127
Because we are a partnership, Section 162(m) of the Internal Revenue Code does not apply to compensation paid to our
named executive officers and accordingly, the CNG Committee did not consider its impact in determining compensation levels in
2014, 2015 or 2016. The CNG Committee has taken into account the tax implications to the partnership in its decision to limit
the long-term incentive compensation to phantom units as opposed to options or restricted units.
Accounting Implications of Executive Compensation
The CNG Committee has considered the partnership accounting implications, particularly the "book-up" cost, of issuing
equity as incentive compensation, and has determined that phantom units offer the best accounting treatment for the partnership
while still motivating and retaining our executive officers.
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, 2016.
Robert T. Blakely, Chairman
Russell D. Gordy
Robert B. Karn III
Leo A. Vecellio, Jr.
128
Summary Compensation Table
The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation for 2014, 2015
and 2016 based on each individual’s allocation of time to Natural Resource Partners:
Name and Principal Position (1)
Corbin J. Robertson, Jr. - Chief Executive
Officer
Wyatt L. Hogan - President and Chief
Operating Officer
Year
2016
2015
2014
2016
2015
2014
$ 400,000
400,000
377,654
$ 450,000
400,000
225,000
Salary
Cash Bonus
Phantom Unit
Awards (2)
All Other
Compensation(3)
$
— $
—
—
— $
—
—
— $
321,912
595,728
— $
—
—
Total
—
321,912
595,728
884,383
994,739
822,155
834,383
1,230,358
562,131
608,612
543,251
534,383
665,085
$
$
$
$
— $
160,956
186,165
— $
446,575
— $
84,949
121,007
— $
239,295
$
$
$
$
34,383
33,783
33,336
34,383
33,783
31,631
33,413
30,869
34,383
30,858
Craig W. Nunez - Chief Financial Officer (4)
Kathryn S. Wilson - Vice President, General
Counsel and Secretary (5)
2016 $ 375,000
375,000
2015
$ 425,000
375,000
2016
2015
2014
$ 305,500
315,250
291,375
$ 225,000
175,000
100,000
Christopher J. Zolas - Chief Accounting
Officer (4)
2016 $ 300,000
244,932
2015
$ 200,000
150,000
(1) In 2016, Messrs. Robertson, Hogan, Nunez, Ms. Wilson and Mr. Zolas spent approximately 50%, 100%, 100%, 94% and
100%, respectively, of their time on NRP matters.
(2) Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards
Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in
calculating these amounts, see Note 16 to the audited consolidated financial statements included elsewhere in this Annual
Report on Form 10-K.
(3) Includes portions of 401(k) matching and retirement contributions allocated to Natural Resource Partners by Quintana.
(4) Messrs. Nunez and Zolas were not named executive officers for purposes of this Summary Compensation Table during
2014.
(5) Amounts for Ms. Wilson’s base salary and all other compensation columns represent the amounts allocated to NRP.
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The following table sets forth the GP Bonus Awards paid by the general partner and not reimbursed by NRP as described
above. These GP Bonus Award amounts are not included in the summary compensation table:
Name and Principal Position
Corbin J. Robertson, Jr. - Chief Executive Officer
Wyatt L. Hogan - President and Chief Operating Officer
Craig W. Nunez - Chief Financial Officer
Kathryn S. Wilson - Vice President, General Counsel and Secretary
Christopher J. Zolas - Chief Accounting Officer
Grants of Plan-Based Awards in 2016
The following table sets forth the cash incentive awards granted in 2016:
Year
2016
2015
2014
2016
2015
2014
2016
2015
2016
2015
2014
2016
2015
Amount
40,114
160,000
180,000
40,114
160,000
384,000
40,114
160,000
40,114
125,000
180,000
40,114
52,000
$
$
$
$
$
$
Named Executive Officer
Corbin J. Robertson, Jr.
Wyatt L. Hogan
Craig W. Nunez
Kathryn S. Wilson
Christopher J. Zolas
Estimated Future Payouts Under Non-Equity
Incentive Plan Awards (1)
Grant Date
3/10/2016
3/10/2016
3/10/2016
3/10/2016
3/10/2016
Threshold
$ 2,000,000
1,000,000
750,000
600,000
300,000
Target
$ 2,000,000
1,000,000
750,000
600,000
300,000
Maximum
$ 3,500,000
1,750,000
1,312,500
1,050,000
450,000
(1) Amounts include both time-vesting and performance based awards granted under the 2016 cash long-term incentive plan
detailed above. One-half or each time vesting award granted in 2016 vested in February 2017.
None of our executive officers has an employment agreement, and the salary, bonus and phantom unit awards noted above
are approved by the CNG Committee. See our disclosure under "—Compensation Discussion and Analysis" for a description of
the factors that the CNG Committee considers in determining the amount of each component of compensation.
Subject to the rules of the exchange upon which the common units are listed at the time, the Board and the CNG Committee
have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time.
Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would
materially reduce any award to a participant without the consent of the participant.
The CNG Committee may make grants under our long-term incentive plans to employees and directors containing such
terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of NRP, our general partner
or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the Board terminates for any reason, outstanding
grants will be automatically forfeited unless and to the extent the CNG Committee provides otherwise.
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As stated above under "—Compensation Discussion and Analysis," we have no outstanding option grants, and do not intend
to grant any options or restricted unit awards in the future. In addition, the CNG Committee determined to make cash long-term
incentive awards in 2016 in lieu of phantom unit awards as described above under "—Compensation Discussion and Analysis—
2016 Cash Long-Term Incentive Plan." The CNG Committee may determine to make additional awards of phantom units in the
future.
Phantom Units Vested in 2016
The table below shows the phantom units that vested in 2016 with respect to each named executive officer, along with the
phantom unit value realized by each individual:
Named Executive Officer
Corbin J. Robertson, Jr.
Wyatt L. Hogan
Craig W. Nunez
Kathryn S. Wilson
Christopher J. Zolas
Phantom Units
Vested in 2016 (1)
Value Realized on
2016 Vesting
$
3,200
1,600
1,100
550
600
220,928
110,464
14,344
25,872
7,824
(1) The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective
on February 17, 2016.
Outstanding Equity Awards at December 31, 2016
The table below shows the total number of outstanding phantom units held by each named executive officer at December 31,
2016. The phantom units shown below were awarded in February 2013, 2014 and 2015, with a portion of the phantom units having
vesting in February 2017 and the remaining portion vesting in each of 2018 and 2019.
Named Executive Officer
Corbin J. Robertson, Jr.
Wyatt L. Hogan
Craig W. Nunez
Kathryn S. Wilson
Christopher J. Zolas
Unvested
Phantom Units (1)
Market Value
of Unvested
Phantom Units (2)
10,160 (3) $
5,080 (4)
3,900 (5)
2,283 (6)
2,400 (7)
328,168
164,084
125,970
73,741
77,520
(1) The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective
on February 17, 2016.
(2) Based on a unit price of $32.30, the closing price for the common units on December 31, 2016.
(3) Includes 3,200 phantom units vested in February 2017, and 3,360 and 3,600 phantom units vesting in February 2018 and
2019, respectively.
(4) Includes 1,600 phantom units vested in February 2017, and 1,680 and 1,800 phantom units vesting in February 2018 and
2019, respectively.
(5) Includes 1,200 phantom units vested in February 2017, and 1,300 and 1,400 phantom units vesting in February 2018 and
2019, respectively.
(6) Includes 650 phantom units vested in February 2017, and 683 and 950 phantom units vesting in February 2018 and 2019,
respectively.
(7) Includes 650 phantom units vested in February 2017, and 800 and 950 phantom units vesting in February 2018 and 2019,
respectively.
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Potential Payments upon Termination or Change in Control
None of our executive officers have entered into employment agreements with Natural Resource Partners or its affiliates.
Consequently, there are no severance benefits payable to any executive officer upon the termination of their employment. Upon
the occurrence of a change in control of NRP, our general partner or GP Natural Resource Partners LLC, the outstanding phantom
unit awards held by each of our executive officers would immediately vest. The table below indicates the impact of a change in
control on (1) the outstanding cash awards under the 2016 Cash Long-Term Incentive Plan and (2) the outstanding equity-based
awards at December 31, 2016, based on a unit price of $34.65, the 20-day average common unit price as of December 31, 2016,
as required pursuant to the term of the phantom units.
Named Executive Officer
Corbin J. Robertson, Jr.
Wyatt L. Hogan
Craig W. Nunez
Kathryn S. Wilson
Christopher J. Zolas
2016 Cash Long-Term Incentive
Plan Awards
$
Time-Based
Awards (1)
500,000
250,000
187,500
150,000
150,000
Performance-
Based
Awards (1)
$ 1,500,000
750,000
562,500
450,000
150,000
Phantom Unit Long-Term Incentive Awards
Unvested
Phantom
Units (2)
10,160
5,080
3,900
2,283
2,400
Market Value
of Unvested
Phantom Units
351,993
$
175,997
135,116
79,095
$
Accumulated
DERs
196,988
98,494
15,795
40,908
83,148
9,720
Total Potential
Payments
$ 2,548,981
1,274,491
(3)
900,911
720,003
392,868
(4)
(1) The outstanding awards vest 100% upon a change in control.
(2) The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective
on February 17, 2016.
(3) Phantom units vested in 2017 and phantom units vesting in 2018 and 2019 include accrued DERs from February 11, 2015,
the date of the grant of these units to Mr. Nunez.
(4) Phantom units vested in 2017 and phantom units vesting in 2018 and 2019 include accrued DERs from March 9, 2015,
the date of the grant of these units to Mr. Zolas.
Directors’ Compensation for the Year Ended December 31, 2016
The table below shows the directors’ compensation for the year ended December 31, 2016. As with our named executive
officers, we do not grant any options or restricted units to our directors:
Name of Director
Robert Blakely
Russell Gordy
Trey Jackson
Robert Karn III
S. Reed Morian
Richard Navarre
Corbin J. Robertson, III
Stephen Smith
Leo A. Vecellio, Jr.
Fees Earned or Paid
in Cash (1)
Total (2)
$
$
85,000
65,000
43,022
85,000
60,000
65,000
60,000
80,000
65,000
85,000
65,000
43,022
85,000
60,000
65,000
60,000
80,000
65,000
(1) In 2016, the annual retainer for the directors was $60,000, and the directors did not receive any additional fees for attending
meetings. Each chairman of a committee received an annual fee of $10,000 for serving as chairman, and each committee
member received $5,000 for serving on a committee.
(2) No phantom unit awards were made to our directors in 2016. As of December 31, 2016, each director other than Mr.
Jackson held 1,169 phantom units, of which 370 phantom units vested in February 2017, and 389 and 410 phantom units
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will vest in February 2018 and 2019, respectively. The awards amounts included in the foregoing sentence give effect to
NRP’s one-for-ten (1:10) reverse common unit split that became effective on February 17, 2016.
The table below shows the phantom units that vested in 2016 with respect to each Director, along with the value realized by
each individual:
Director
Robert Blakely
Russell Gordy
Trey Jackson
Robert Karn III
S. Reed Morian
Richard Navarre
Corbin J. Robertson, III
Stephen Smith
Leo A. Vecellio, Jr.
Phantom Units
Vested in 2016 (1)
Value Realized on
2016 Vesting
$
370
370
—
370
370
370
370
370
370
25,545
12,336
—
25,545
25,545
12,336
14,371
25,545
25,545
(1) The unit numbers in the table above give effect to NRP's one-for-ten (1:10) reverse common unit split that became effective
on February 17, 2016.
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2016, Messrs. Blakely, Gordy, Karn and Vecellio served on the CNG Committee. None
of Messrs. Blakely, Gordy, Karn or Vecellio 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.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of March 2, 2017, the amount and percentage of our common 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 the directors and 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. The information presented below gives effect
to the one-for-ten reverse unit split that was effective on February 17, 2016.
Name of Beneficial Owner
Corbin J. Robertson, Jr. (2)
Premium Resources LLC (3)
Wyatt L. Hogan (4)
Craig W. Nunez
Kevin J. Craig
Kathy H. Roberts
Kathryn S. Wilson
Gregory F. Wooten
Christopher J. Zolas
Robert T. Blakely
Russell D. Gordy(5)
L.G. (Trey) Jackson III
Robert B. Karn III
Jasvinder S. Khaira
S. Reed Morian
Richard A. Navarre
Corbin J. Robertson III (6)
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
1,250
—
1,800
2,000
—
—
—
2,500
7,000
—
500
—
—
1,000
172,790
355
2,000
4,319,550
33.8%
33.8%
*
—
*
*
*
*
*
—
—
—
—
—
—
*
1.4%
*
*
35.3%
(1) Percentages based upon 12,232,006 common units issued and outstanding as of March 2, 2017. 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) Of these common units, 50 common units are owned by the Anna Margaret Hogan 2002 Trust, 50 common units are owned
by the Alice Elizabeth Hogan 2002 Trust, and 50 common units are held by the Ellen Catlett Hogan 2005 Trust. Mr. Hogan
is a trustee of each of these trusts.
(5) 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.
(6) Mr. Robertson 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,
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Suite 2400, Houston, Texas 77002. The following common units are pledged as collateral for loans: 29,542 common units
owned directly by Mr. Robertson.
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 and is the Chairman and Chief Executive Officer of New
Gauley Coal Corporation.
Omnibus Agreement
Non-competition Provisions
As part of the omnibus agreement entered into concurrently with the closing of our initial public offering, the WPP Group
and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the GP affiliates, each agreed that neither
they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a
"restricted business") in the specific circumstances described below:
•
•
the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned
fee coal reserves within the United States; and
the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within
the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.
"Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more
intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described
below, the WPP Group and their respective controlled affiliates will not be prohibited from engaging in activities in which they
compete directly with us.
A GP affiliate may, directly or indirectly, engage in a restricted business if:
•
•
•
the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value
of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must
offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided
that if the fair market value of the assets of the restricted business subsequently exceeds $10 million, the GP affiliate
must offer the restricted business to us under the offer procedures described below.
the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the
general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under
the procedures described below.
•
its ownership in the restricted business consists solely of a non-controlling equity interest.
For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant
GP affiliate.
The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP
Group, other than those engaged in by the WPP Group at closing of our initial public offering, may not exceed $75 million. For
purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will
be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be
acquired.
If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market
value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired,
then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a
135
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.
Board Representation and Observation Rights Agreement
Effective on March 2, 2017 in connection with the closing of the issuance of the Preferred Units, pursuant to the Board
Representation and Observation Rights Agreement, Blackstone appointed Jasvinder S. Khaira to serve on the Board of Directors
of GP Natural Resource Partners LLC and also appointed 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 the Minimum Preferred Unit Threshold (as defined elsewhere in this Annual Report on Form 10-K). 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. The
Board Representation and Observation Rights Agreement is filed as Exhibit 4.29 to this Annual Report on Form 10-K and herein
incorporated by reference.
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Restricted Business Contribution Agreement
In connection with our partnership with Christopher Cline and his affiliates, Mr. Cline, Foresight Reserves LP and Adena
(collectively, the "Cline Parties") and NRP have executed a Restricted Business Contribution Agreement. Pursuant to the terms of
the Restricted Business Contribution Agreement, the Cline Parties and their affiliates are obligated to offer to NRP any business
owned, operated or invested in by the Cline Parties, subject to certain exceptions, that either (a) owns, leases or invests in hard
minerals or (b) owns, operates, leases or invests in transportation infrastructure relating to future mine developments by the Cline
Parties in Illinois. In addition, we created an area of mutual interest (the "AMI") around certain of the properties that we have
acquired from Cline affiliates. During the applicable term of the Restricted Business Contribution Agreement, the Cline Parties
will be obligated to contribute any coal reserves held or acquired by the Cline Parties or their affiliates within the AMI to us. In
connection with the offer of mineral properties by the Cline Parties to NRP, the parties to the Restricted Business Contribution
Agreement will negotiate and agree upon an area of mutual interest around such minerals, which will supplement and become a
part of the AMI.
We have made several acquisitions from Cline affiliates pursuant to the Restricted Business Contribution Agreement. 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 13. Related Party Transactions—Cline Affiliates" elsewhere in this Annual
Report on Form 10-K.
Mr. Holcomb, who was appointed to the Board in October 2013 and resigned from the Board in April 2016, previously
served as Chief Financial Officer for Foresight Reserves LP and its subsidiaries. Mr. Holcomb owned a less than 1% equity interest
in certain Cline affiliates until March 2013 when he fully divested from all Cline affiliates. As a result of his position as an executive
officer and an equity holder of certain Cline affiliates, Mr. Holcomb may be deemed to have had an indirect material interest in
the transactions with the Cline affiliates described in this Annual Report on Form 10-K.
Mr. Holcomb is a manager of Cline Trust Company, LLC, which owns common units and 2018 Notes. The members of the
Cline Trust Company are four trusts for the benefit of the children of Christopher Cline, each of which owns an approximately
equal membership interest in the Cline Trust Company. Mr. Holcomb also serves as trustee of each of the four trusts.
Investor Rights Agreement
NRP and certain affiliates and Adena executed an Investor Rights Agreement pursuant to which Adena was granted certain
management rights. Specifically, Adena has the right to name two directors (one of which must be independent) to the Board of
Directors of our managing general partner so long as Adena beneficially owns either 5% of our limited partnership interest or 5%
of our general partner’s limited partnership interest and so long as certain rights under our managing general partner’s LLC
Agreement have not been exercised by Adena or Mr. Robertson. Leo A. Vecellio and L.G. (Trey) Jackson III currently serve as
Adena’s two directors. Mr. Vecellio serves on our CNG Committee. Adena will also have the right, pursuant to the terms of the
Investor Rights Agreement, to withhold its consent to the sale or other disposition of any entity or assets contributed by Cline
affiliates to NRP, and any such sale or disposition will be void without Adena’s consent.
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:
137
• The ownership of non-operating working interests in oil and gas properties.
• The ownership of non-controlling equity interests in companies involved in natural resource development and extraction.
• The operation of construction aggregates mining and production businesses.
The businesses and investments described in this paragraph are referred to as the "Shared Businesses."
NRP’s business strategy does not, and is not expected to, include:
• The ownership of equity interests in companies involved in the mining or extraction of coal.
•
•
Investments that do not generate "qualifying income" for a publicly traded partnership under U.S. tax regulations.
Investments outside of North America.
• Midstream or refining businesses that do not involve hard extracted minerals, including the gathering, processing,
fractionation, refining, storage or transportation of oil, natural gas or natural gas liquids.
In addition, although NRP’s current oil and gas strategy is focused on the acquisition of minerals, royalties and non-operated
working interests, NRP may also consider the acquisition of operated interests. 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, is Chairman of the Board
of Corsa.
For more information on our relationship with Corsa Coal, see "Item 8. Financial Statements and Supplemetary Data—Note
13. Related Party Transactions—Quintana Capital Group GP, Ltd."
138
Office Building in Huntington, West Virginia
We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The
terms of the lease, including $0.6 million per year in lease payments, were approved by our conflicts committee.
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, the Cline entities, and their affiliates) 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.
Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding
such matters as:
•
•
•
amount and timing of asset purchases and sales;
cash expenditures;
borrowings;
139
•
•
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.
Excluding VantaCore, we do not have any officers or employees and rely solely on officers and employees of GP Natural
Resource Partners LLC and its affiliates.
Excluding our VantaCore business, we do not have any officers or employees and rely solely 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. These officers devote
significant time to the affairs of the WPP Group or its affiliates and are compensated by these affiliates for the services rendered
to them.
We reimburse our general partner and its affiliates for expenses.
We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred
in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines
the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to
our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general
partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained
more favorable terms without the limitation on liability.
Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the
unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-
length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided
these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual
arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts
and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length
negotiations.
All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and
its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our
general partner or its affiliates to enter into any contracts of this kind.
140
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, the Omnibus Agreement and
the Restricted Business Contribution Agreement, affiliates of our general partner will not be prohibited from engaging in activities
in which they compete directly with us.
As a result of the purchase of the Preferred Units, 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 and our general partner on the
one hand, and Blackstone or GoldenTree on the other hand.
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,
the Cline entities, Blackstone, GoldenTree, and their affiliates) 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, the Restricted Business Contribution Agreement,
and our partnership agreement. For the year ended December 31, 2016, there were no transactions where such guidelines were
not followed.
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 2016 and 2015. 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)
2016
2015
$
$
1,010,002
746,463
1,980
1,192,306
773,005
2,400
(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
141
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.
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.
142
II. Delegation
As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to
Robert B. Karn III, the Chairman of the Audit Committee. Mr. Karn 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.
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.
143
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.
144
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
2.3
2.4
3.1
3.2
3.3
3.4
3.5
3.6
4.1
4.2
4.3
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).
Agreement and Plan of Merger, dated as of August 18, 2014, by and among VantaCore Partners LP, VantaCore LLC,
the Holders named therein, Natural Resource Partners L.P., NRP (Operating) LLC and Rubble Merger Sub, LLC
(incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on August 20, 2014).
Interest Purchase Agreement, by and among NRP Oil and Gas LLC, Kaiser-Whiting, LLC and the Owners of Kaiser-
Whiting, LLC dated as of October 5, 2014 (incorporated by reference to Current Report on Form 8-K filed on October
6, 2014).
Purchase and Sale Agreement dated as of June 13, 2016 by and between NRP Oil and Gas LLC and Lime Rock
Resources IV-A, L.P.
Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of
September 20, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 21,
2010).
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).
145
Exhibit
Number
4.4
4.5
4.6
4.7
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
4.25
Description
First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the
purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on July
20, 2005).
Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and
the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on
March 29, 2007).
Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the
purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March
26, 2009).
Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the
purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April
21, 2011).
Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to
Exhibit 4.5 to Current Report on Form 8-K filed June 23, 2003).
Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed June 23, 2003).
Form of Series B Note (incorporated by reference to Exhibit 4.3 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).
Indenture, dated September 18, 2013, by and among Natural Resource Partners L.P. and NRP Finance Corporation,
as issuers, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current
Report on Form 8-K filed on September 19, 2013).
Form of 9.125% Senior Notes due 2018 (contained in Exhibit 1 to Exhibit 4.20).
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 4.24).
146
Exhibit
Number
4.26
4.27
4.28
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
Description
Registration Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P., NRP
Finance Corporation, and the Initial Notes Purchasers named therein (incorporated by reference to Exhibit 4.5 to
Current Report on Form 8-K filed on March 6, 2017).
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).
Contribution Agreement, dated as of September 20, 2010, by and among Natural Resource Partners L.P., NRP (GP)
LP, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley
Coal Corporation and NRP Investment L.P. (incorporated by reference to Exhibit 10.1 to Current Report on Form
8-K filed on September 21, 2010).
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).
Restricted Business Contribution Agreement, dated January 4, 2007, by and among Christopher Cline, Foresight
Reserves LP, Adena Minerals, 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 Current Report on Form 8-K filed on
January 4, 2007).
Investor Rights Agreement, dated January 4, 2007, by and among NRP (GP) LP, GP Natural Resource Partners LLC,
Robertson Coal Management and Adena Minerals, LLC (incorporated by reference to Exhibit 10.2 to Current Report
on Form 8-K filed on January 4, 2007).
Waiver Agreement, dated November 12, 2009, by and among Natural Resource Partners L.P., Great Northern
Properties Limited Partnership, Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation,
Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC
(incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on November 13, 2009).
Limited Liability Company Agreement of Ciner Wyoming LLC, dated June 30, 2014 (incorporated by reference to
Exhibit 10.1 to Current Report on Form 8-K filed by Ciner Resources LP on July 2, 2014).
Amendment No. 1 to the Limited Liabiltiy 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).
Credit Agreement, dated as of August 12, 2013, among NRP Oil and Gas LLC, Wells Fargo Bank, N.A., as
Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole Lead Arranger (incorporated
by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 13, 2013).
First Amendment to Credit Agreement, dated effective as of December 19, 2013, among NRP Oil and Gas LLC,
Wells Fargo Bank, N.A., as Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole
Lead Arranger (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on December 20,
2013).
147
Exhibit
Number
10.12
10.13
10.14
10.15
10.16
10.17
Description
Second Amendment to Credit Agreement entered into effective as of November 12, 2014 among NRP Oil and Gas
LLC, each of the Lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the
Lenders (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on November 14, 2014).
Fourth Amendment to Credit Agreement entered into effective as of March 21, 2016 among NRP Oil and Gas LLC,
each of the Lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the Lenders
(incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 22, 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)
10.18*** 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).
10.19***
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).
10.20*** Natural Resource Partners Annual Incentive Plan (incorporated by reference to Exhibit 10.4 to Annual Report on
Form 10-K for the year ended December 31, 2002).
10.21*** Natural Resource Partners L.P. 2016 Cash Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to
Current Report on Form 8-K filed on February 26, 2016).
10.22***
10.23***
21.1*
23.1*
Form of Long-Term Incentive Award Agreement (incorporated by reference to Exhibit 10.2 to Current Report on
Form 8-K filed on February 26, 2016).
Form of Long-Term Performance Award Agreement (incorporated by reference to Exhibit 10.3 to Current Report
on Form 8-K filed on February 26, 2016).
List of subsidiaries of Natural Resource Partners L.P.
Consent of Ernst & Young LLP.
148
Exhibit
Number
Description
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 and for the years ended December 31, 2016, 2015 and 2014.
23.2*
31.1*
31.2*
32.1**
32.2**
95.1*
99.1*
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Labels Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
*
**
***
Filed herewith
Furnished herewith
Management compensatory plan or arrangement
149
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 6, 2017
Date: March 6, 2017
Date: March 6, 2017
NATURAL RESOURCE PARTNERS L.P.
By: NRP (GP) LP, its general partner
By: GP NATURAL RESOURCE
PARTNERS LLC, its general partner
By:
/s/ CORBIN J. ROBERTSON, JR.
Corbin J. Robertson, Jr.
Chairman of the Board, Director and
Chief Executive Officer
(Principal Executive Officer)
By:
/s/ CRAIG W. NUNEZ
Craig W. Nunez
Chief Financial Officer and
Treasurer
(Principal Financial Officer)
By:
/s/ CHRISTOPHER J. ZOLAS
Christopher J. Zolas
Chief Accounting Officer
(Principal Accounting Officer)
150
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 6, 2017
Date: March 6, 2017
Date: March 6, 2017
Date: March 6, 2017
Date: March 6, 2017
Date: March 6, 2017
Date: March 6, 2017
Date: March 6, 2017
Date: March 6, 2017
Date: March 6, 2017
/s/ ROBERT T. BLAKELY
Robert T. Blakely
Director
/s/ RUSSELL D. GORDY
Russell D. Gordy
Director
L. G. (Trey) Jackson III
Director
/s/ ROBERT B. KARN III
Robert B. Karn III
Director
Jasvinder S. Khaira
Director
/s/ S. REED MORIAN
S. Reed Morian
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
151
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
VantaCore Partners LLC
Laurel Aggregates Terminal Services of Delaware, LLC
Laurel Aggregates of Delaware, LLC
Laurel Aggregates of PA, LLC
Utica Resources LLC
Winn Materials, LLC
Winn Materials of Kentucky, LLC
Winn Marine, LLC
McIntosh Construction Company, LLC
McAsphalt. LLC
Southern Aggregates, LLC
Lake Lynn Transportation 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 Registration Statement (Form S-3 No. 333-207034, Form S-3 No. 333-183314,
and Form S-3 No. 333-187883) of Natural Resource Partners L.P., and in the related Prospectus of our reports dated March 6,
2017, 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) for the year ended
December 31, 2016.
/s/ Ernst & Young LLP
Houston, Texas
March 6, 2017
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statements on Form S-3 (Nos. 333-207034, 333-183314, and
333-187883) of Natural Resource Partners L.P., of our report dated March 6, 2017, relating to the financial statements of Ciner
Wyoming LLC as of December 31, 2016 and 2015, and for the three years in the period ended December 31, 2016, appearing in
the Annual Report on Form 10-K of Natural Resource Partners L.P. for the year ended December 31, 2016.
Exhibit 23.2
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 6, 2017
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 6, 2017
Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
I, Craig W. Nunez, 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/ Craig W. Nunez
Craig W. Nunez
Chief Financial Officer
Date: March 6, 2017
Exhibit 32.1
CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
In connection with the accompanying report on Form 10-K for the year ended December 31, 2016 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 6, 2017
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, 2016 filed with the Securities
and Exchange Commission on the date hereof (the “Report”), I, Craig W. Nunez, 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/ Craig W. Nunez
Craig W. Nunez
Chief Financial Officer
Date: March 6, 2017
Exhibit 95.1
MINE SAFETY DISCLOSURE
Our 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. 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 12-month period ending December 31st, 2016.
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 1/16-01388
Southern Aggregates/Plant 6/16-00336
Southern Aggregates/Plant 7/16-01519
Southern Aggregates/Plant 7.2/16-01551
Southern Aggregates/Plant 9/16-01536
Southern Aggregates/Plant 11/16-01537
Southern Aggregates/Plant 12/16-01546
Southern Aggregates/Plant 15/16-01550
Southern Aggregates/Plant 16/16-01563
3
0
2
0
0
0
1
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
0
0
0
0
0
0
0
$2,759
$428
$1,536
$0
$0
$0
$364
$514
$300
$0
$114
$214
(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 ending December 31st, 2016 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 2016: Winn Materials Clarksville-Six (6) vacated 104(a) citations; Laurel Aggregates-Three (3) vacated 104(a) citations;
Southern Aggregates-Three (3) 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 1/16-01388
Southern Aggregates Plant 6/16-00336
Southern Aggregates Plant 7/16-01519
Southern Aggregates Plant 7.2/16-01551
Southern Aggregates Plant 9/16-01536
Southern Aggregates/Plant 11/16-01537
Southern Aggregates Plant 12/16-01546
Southern Aggregates/Plant 15/16-01550
Southern Aggregates/Plant 16/16-01563
Total Number of
Mining Related
Fatalities
Received Notice of
Pattern of
Violations Under
Section 104(e)
(yes/no) (1)
0
0
0
0
0
0
0
0
0
0
0
0
N
N
N
N
N
N
N
N
N
N
N
N
Legal Actions
Pending as of Last
Day of Period
Legal Actions
Initiated During
Period
Legal Actions
Resolved During
Period
12
16
24
1
4
0
0
0
0
3
1
0
1
1
0
6
2
0
0
1
3
0
0
1
1
0
5
2
4
0
2
2
0
0
0
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 31st,
2016, 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
10
Winn Materials of KY-Grand
Rivers/15-19561
Laurel Aggregates/36-08891
Southern Aggregates/Plant 1/16-01388
Southern Aggregates Plant 6/16-00336
Southern Aggregates Plant 7/16-01519
Southern Aggregates Plant 7.2/16-01551
Southern Aggregates Plant 9/16-01536
Southern Aggregates/Plant 11/16-01537
Southern Aggregates Plant 12/16-01546
Southern Aggregates/Plant 15/16-01550
Southern Aggregates/Plant 16/16-01563
0
0
0
0
0
0
0
0
0
0
0
2
1
4
0
0
0
0
3
1
0
1
1
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
0
0
Exhibit 99.1
Ciner Wyoming LLC
(A Majority-Owned Subsidiary of Ciner Resources LP)
Financial Statements as of December 31, 2016 and 2015 and for the Years Ended
December 31, 2016, 2015, and 2014, 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, 2016 AND 2015
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED
DECEMBER 31, 2016, 2015 AND 2014
STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 2016, 2015 AND 2014
STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
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
We have audited the accompanying balance sheets of Ciner Wyoming LLC (the “Company”) as of December 31, 2016 and 2015,
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, 2016. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)
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.
The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.
Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, 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. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such financial statements referred to above present fairly, in all material respects, the financial position of the
Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
March 6, 2017
3
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
BALANCE SHEETS
AS OF DECEMBER 31, 2016 AND 2015
(In thousands of dollars)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Accounts receivable - ANSAC
Accounts receivable - other affiliate
Due from affiliates, 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
MEMBERS' EQUITY:
Members’ equity — Ciner Resources LP
Members’ equity — Natural Resource Partners LP
Accumulated other comprehensive loss
Total members' equity
2016
2015
$
$
18,728
33,394
46,467
9,054
6,299
19,014
1,660
18,158
33,788
52,211
—
12,325
26,376
1,837
134,616
144,695
214,455
212,819
20,972
21,026
$
370,043
$
378,540
$
$
8,600
14,953
4,207
27,636
—
13,351
4,634
25,033
55,396
43,018
89,400
110,000
9,025
6,808
153,821
159,826
111,945
107,556
(3,279
113,681
109,224
(4,191
216,222
218,714
TOTAL LIABILITIES AND MEMBERS' EQUITY
$
370,043
$
378,540
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, 2016, 2015 AND 2014
(In thousands of dollars)
SALES - AFFILIATES
SALES - OTHERS
Total net sales
COST OF PRODUCTS SOLD
FREIGHT COSTS
Total cost of products sold
GROSS PROFIT
2016
2015
2014
$
271,274
203,913
475,187
241,353
119,602
$
$
265,289
221,104
486,393
232,853
122,047
236,685
228,347
465,032
222,848
123,745
360,955
354,900
346,593
114,232
131,493
118,439
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES
17,575
13,904
16,192
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS
LOSS ON DISPOSAL OF ASSETS, NET
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest income
Interest expense
Other income (expense), net
Total other income (expense)
NET INCOME
OTHER COMPREHENSIVE INCOME (LOSS)
1,258
271
1,315
202
577
1,032
95,128
116,072
100,638
48
(3,550)
(30)
31
(3,975)
(478)
78
(5,140)
1,064
(3,532)
(4,422)
(3,998)
91,596
111,650
96,640
Income (loss) on derivative financial instruments
912
(3,443)
(198)
COMPREHENSIVE INCOME
See notes to financial statements.
$
96,442
$
96,442
$
96,442
5
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
STATEMENTS OF MEMBERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
(In thousands of dollars)
Ciner
Resources LP
Natural Resource
Partners LP
Accumulated
Other
Comprehensive
Income (Loss)
Total Members'
Equity
$
$
$
$
100,919
$
96,962
$
(550) $
197,331
49,286
(44,760)
—
47,354
(43,005)
—
—
—
(198)
96,640
(87,765)
(198)
105,445
$
101,311
$
(748) $
206,008
56,941
(48,705)
—
54,709
(46,769)
—
—
—
(3,443)
111,650
(95,501)
(3,443)
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
Balance at December 31, 2013
Allocation of net income
Capital distribution to members
Other comprehensive income (loss)
Balance at December 31, 2014
Allocation of net income
Capital distribution to members
Other comprehensive income (loss)
Balance at December 31, 2015
Allocation of net income
Capital distribution to members
Other comprehensive income (loss)
Balance at December 31, 2016
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, 2016, 2015 AND 2014
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
91,596
$
111,650
$
96,640
2016
2015
2014
Depreciation, depletion and amortization
Loss on disposal of assets, net
Other non-cash items
(Increase) decrease in:
Accounts receivable, net
Accounts receivable - ANSAC
Accounts receivable - other affiliate
Inventory
Other current and non-current assets
Due from affiliates, net
Increase (decrease) in:
Accounts payable
Accrued expenses and other liabilities
Due to affiliates
25,697
271
422
394
5,744
(9,054)
6,968
524
6,026
1,131
3,618
(426)
22,870
202
755
1,668
18,199
—
(3,660)
(816)
7,163
1,792
(5,312)
(713)
21,587
1,032
(203)
(1,055)
(12,359)
—
(1,499)
(153)
905
(3,535)
3,230
4,971
Net cash provided by operating activities
132,911
153,798
109,561
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
Proceeds from sale of fixed assets
(25,341)
—
(35,659)
—
(27,255)
10
Net cash used in investing activities
(25,341)
35,659
(27,245)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments on revolving credit facility
Borrowings on revolving credit facility
Cash distribution to members
(27,000)
15,000
(95,000)
(40,000)
5,000
(95,501)
(10,000)
—
(87,765)
Net cash used in financing activities
(107,000)
(130,501)
(97,765)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
570
(12,362)
(15,449)
CASH AND CASH EQUIVALENTS:
Beginning of year
End of year
SUPPLEMENTAL DISLCOSURE OF CASH FLOW INFORMATION:
Interest paid during the year
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES :
Capital expenditures on account
See notes to financial statements
18,158
30,520
45,969
18,782
$
18,158
$
30,520
3,213
$
4,059
$
4,274
3,938
$
3,033
$
4,579
$
$
$
7
CINER WYOMING LLC
(A Majority Owned Subsidiary of Ciner Resources LP)
NOTES TO FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2016 AND 2015 AND FOR THE YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014
(Dollars in thousands)
8
1. Corporate Structure
A 51% membership interest in Ciner Wyoming LLC (the "Company," "we," "us," or "our") is owned by Ciner Resources
LP (CINR or the "Partnership"). NRP Trona LLC, a wholly owned subsidiary of Natural Resource Partners LP (NRP) owns
a 49% membership interest in the Company. CINR is a master limited partnership traded on the New York Stock exchange
and is currently owned approximately 75% by Ciner Wyoming Holding Co. (CINWHCO) and approximately 25% by the
general public. CINWHCO is 100% owned by Ciner Resources Corporation (CRC) which is ultimately 100% owned by
Ciner Enterprises, Inc. (CINE). CINE is 100% owned by Akkan Enerji ve Madencilik Anonim
("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.
Completed sale transaction - On October 23, 2015, CINE acquired 100% of OCI Chemical Corporation in a stock purchase
transaction from OCI Enterprises Inc. ("OCIE") (the "Transaction"). OCI Chemical Corporation was subsequently renamed
Ciner Resources Corporation. CRC owns indirectly the Company through CINWHCOs approximately 75% ownership
interest in CINR. As a result of the closing of the Transaction, OCIE no longer has any direct or indirect ownership interest
in the Company.
In connection with the closing of the Transaction, CINE (as borrower), and CINWHCO and CRC (as guarantors), entered
into a credit facility (as amended and restated or otherwise modified, the “Ciner Enterprises Credit Facility”), which is
secured by certain assets, including the common units and the subordinated units of CINR owned by CINWHCO.
2. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations - The Company operations consists of the mining of trona ore, which, when processed, becomes soda
ash. All our soda ash processed is sold to various domestic and European customers, and to Ciner Ic ve Dis Ticaret Anonim
Sirketi (CIDT) and American Natural Soda Ash Corporation (ANSAC) which are affiliates for export sales. All mining and
processing activities take place in one facility located in Green River, Wyoming.
A summary of the significant accounting policies is as follows:
Basis of Presentation - The accompanying financial statements have been prepared in accordance with accounting principles
generally accepted in the United States of America.
Use of Estimates - The preparation of financial statements, in accordance with accounting principles generally accepted in
the United States of America, requires management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, and disclosure of contingent assets and liabilities at the dates of the financial statements, and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition - We recognize revenue when the earnings process is complete, which is generally upon transfer of
title. This transfer typically occurs upon shipment to the customer, which is normally free on board (“FOB”) terms or upon
receipt by the customer. In all cases, we apply the following criteria in recognizing revenue: (1) persuasive evidence of an
arrangement exists; (2) delivery has occurred; (3) the selling price is fixed, determinable or reasonably estimated sales price
has been agreed with the customer; and (4) collectability is reasonably assured. Customer rebates and discounts are accounted
for as sales deductions. We record amounts billed for shipping and handling fees as revenue. Costs incurred for shipping
and handling are recorded as costs of products sold.
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.
9
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. If actual collection experience changes, revisions to the allowance may
be required. Accounts receivable are written off when deemed uncollectible. Recoveries of accounts receivable previously
written off are recorded when received. During the years ended 2016, 2015 and 2014 there were no significant accounts
receivable bad debt expenses, write-offs or recoveries.
Inventory - Inventory is carried at the lower of cost or market. Cost is determined using the first-in, first-out method for raw
material and finished goods inventory and the weighted average cost method for stores inventory. Costs include raw materials,
direct labor and manufacturing overhead. Market is based on current replacement cost for raw materials and net realizable
value for stores inventory and finished goods.
• Raw material inventory includes material, chemicals and natural resources being used in the mining and refining process.
• Finished goods inventory is the finished product soda ash.
• Stores inventory includes parts, materials and operating supplies which are typically consumed in the production of soda
ash and currently available for future use. Inventory expected to be consumed within the year is classified as current assets
and remainder is classified as non-current assets.
Property, Plant, and Equipment - Property, plant, and equipment are stated at cost less accumulated depreciation. Depreciation
is computed over the estimated useful lives of depreciable assets, using the straight-line method. The estimated useful lives
applied to depreciable assets are as follows:
Land improvements
Depletable land
Buildings and building improvements
Internal-use computer software
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 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
10
hedge, the effective portion of the derivative’s gain or loss is initially reported as a component of accumulated other
comprehensive income (loss) and subsequently reclassified into earnings when the hedged exposure affects earnings. Any
significant ineffective portion of the gain or loss is reported in earnings immediately. For derivatives not designated as hedges,
the gain or loss is reported in earnings in the period of change. The natural gas physical forward contracts are accounted for
under the normal purchases and normal sales scope exception.
The company has entered into interest rate swap contracts, designed as cash flow hedges, to mitigate the exposure to possible
increases in interest rates. These contracts are for periods consistent with the exposure being hedged and will mature on July
18, 2018, the maturity date of the long-term debt under the Ciner Wyoming Credit Facility. These contracts had an aggregate
notional value of $72,000 and $74,000 at December 31, 2016 and December 31, 2015, respectively. At December 31, 2016,
it was anticipated that approximately $400 of losses currently recorded in accumulated other comprehensive income (loss)
will be reclassified into earnings within the next 12 months.
The Company has entered into 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 2021. These contracts
had an aggregate notional value of $30,969 and $15,831 at December 31, 2016 and December 31, 2015, respectively. At
December 31, 2016, it was anticipated that $601 of gains currently recorded in accumulated other comprehensive income
(loss) will be reclassified into earnings within the next 12 months.
The Company entered into foreign exchange forward contracts to hedge certain firm commitments denominated in currencies
other than the U.S. dollar. However, the Company did not apply hedge accounting for these contracts at December 31, 2015.
These contracts were for periods consistent with the exposure being hedged and generally had maturities of one year or less.
These contracts, which were predominantly used to purchase U.S. dollars and sell Euros, had an aggregate notional value
of $4,160 at December 31, 2015. The Company had no similar contracts outstanding as of December 31, 2016.
The following table presents the fair value of derivative assets and liabilities and the respective balance sheet locations as
of:
Assets
Liabilities
December 31,
2016
December 31,
2015
December 31,
2016
December 31,
2015
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
Balance
Sheet
Location
Fair
Value
(In millions)
Derivatives designated as
hedges:
Interest rate swap contracts -
current
$
—
$
—
Accrued
Expenses
$
439
Natural gas forward contracts -
current
Other
current
assets
Natural gas forward contracts -
non-current
Total derivatives designated
as hedging instruments
601
—
$
601
$
—
—
—
Accrued
Expenses
Accrued
Expenses
Other
non-
current
liabilities
$
819
1,021
2,351
Other
non-
current
liabilities
—
3,441
$
3,880
$
4,191
Income Tax - The Company is organized as a pass-through entity for federal income tax purposes. 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.
11
Reclamation Costs - The Company is obligated to return the land beneath its refinery and tailings ponds to its natural condition
upon completion of operations and is required to return the land beneath its rail yard to its natural condition upon termination
of the various lease agreements.
The Company accounts for its land reclamation liability as an asset retirement obligation, which requires that obligations
associated with the retirement of a tangible long-lived asset be recorded as a liability when those obligations are incurred,
with the amount of the liability initially measured at fair value. Upon initially recognizing a liability for an asset retirement
obligation, an entity must capitalize the cost by recognizing an increase in the carrying amount of the related long-lived
asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the
estimated useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded
amount or incurs a gain or loss upon settlement.
The estimated original liability calculated in 1996 for the refinery and tailing ponds was calculated based on the estimated
useful life of the mine, which was 80 years, and on external and internal estimates as to the cost to restore the land in the
future and state regulatory requirements. In 2017, the mining reserve will be amortized over a remaining life of 66 years.
During 2016, 2015 and 2014 the remaining life was 67 years, 68 years and 66 years, respectively. 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 fair value of our long-term debt is based on present rates for 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.
12
Subsequent Events - The Company has evaluated all subsequent events through March 6, 2017, the date the financial
statements were available to be issued.
Recently Issued Accounting Standards - In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting
Standards Update (“ASU”) No. 2014-09, 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 should apply the guidance in ASU 2014-09 to annual reporting periods beginning
after December 15, 2017, including interim reporting periods within that reporting period. The Company has completed
its initial evaluation of the provisions of this ASU and does not expect our adoption of ASU 2014-09 to materially change
the amount or timing of revenues recognized by us, nor expect it to 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 majority of our contracts with customers, is the point when the product leaves our
facility, thereby rendering our performance obligation fulfilled. The FASB issued various amendments to ASU 2014-09, one
of which includes allowing entities to elect to account for shipping and handling activities performed after the control of a
good has been transferred to the customer as a fulfillment cost versus an obligation of a promised service. The Company
expects to make this an accounting policy election upon adoption. We currently include freight costs billed to customers
for shipments administered by us in gross sales. We will adopt this ASU effective January 1, 2018, and tentatively expect
to apply the modified retrospective (cumulative effect) method of adoption as permitted by the ASU. During 2017, we will
develop our revenue disclosures and enhance our accounting systems, if applicable.
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and
Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). The standard amends certain aspects of
recognition, measurement, presentation, and disclosure of financial assets and liabilities. ASU 2016-01 is effective for fiscal
years, and interim periods within those years, beginning after December 15, 2017. The Company is currently evaluating the
potential impact the adoption of ASU 2016-01 will have on its financial statements, as well as, available transition methods.
In February 2016, the FASB issued ASU No. 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. The update
is effective for interim and annual periods beginning after December 15, 2018 and must be adopted using a modified
retrospective transition. The ASU No. 2016-02 provides for certain practical expedients and early adoption is permitted. The
Company is evaluating the potential impact the adoption of ASU No. 2016-02 will have on its financial statements; however,
based on our current operating leases, it is not expected to have a material impact.
3. ACCOUNTS RECEIVABLE, NET
Accounts receivable, net as of December 31, 2016 and 2015 consists of the following:
Trade receivables
Other receivables
Allowance for doubtful accounts
Total
2016
2015
27,311
6,233
33,544
(150)
33,394
$
$
27,163
6,767
33,930
(142)
33,788
$
$
13
4. INVENTORY
Inventory as of December 31, 2016 and 2015 consists of the following:
Raw materials
Finished goods
Stores inventory, current
Total
2016
2015
7,717
5,764
5,533
19,014
$
$
9,110
10,675
6,591
26,376
$
$
5. PROPERTY, PLANT, AND EQUIPMENT, NET
Property, plant, and equipment as of December 31, 2016 and 2015 consists of the following:
Land and land improvements
Depletable land
Buildings and building improvements
Internal-use computer software
Machinery and equipment
Total
Less accumulated depreciation, depletion and amortization
Total net book value
Construction in progress
Property, plant, and equipment, net
2016
192
2,957
133,149
5,123
598,954
740,375
(570,342)
170,033
44,422
214,455
$
$
2015
192
2,957
132,504
4,863
577,472
717,988
(547,277)
170,711
42,108
212,819
$
$
Depreciation, depletion and amortization expense on property, plant and equipment was $25,345, $22,519 and $21,235 for
the years ended December 31, 2016, 2015 and 2014, respectively.
6. OTHER NON-CURRENT ASSETS
Other non-current assets as of December 31, 2016 and 2015 consists of the following:
Stores inventory, non-current
Deferred financing costs and other
Total
2016
2015
20,671
301
20,972
$
$
20,498
528
21,026
$
$
14
7. ACCRUED EXPENSES
Accrued expenses as of December 31, 2016 and 2015 consists of the following:
Accrued freight costs
Accrued energy costs
Accrued royalty costs
Accrued employee compensation
Accrued other taxes
Accrued derivatives
Other accruals
Total
2016
2015
$
— $
5,582
4,619
6,993
4,812
439
5,191
27,636
$
$
135
5,185
4,834
3,950
4,532
1,841
4,556
25,033
8. DEBT
Long-term debt as of December 31, 2016 and 2015 consists of the following:
Variable Rate Demand Revenue Bonds, principal due October 1, 2018, interest
payable monthly with an interest rate of 0.87% at December 31, 2016 and 0.11% at
December 31, 2015
Variable Rate Demand Revenue Bonds, principal due August 1, 2017, interest
payable monthly with an interest rate of 0.87% at December 31, 2016 and 0.11% at
December 31, 2015
Ciner Wyoming Credit Facility, unsecured principal expiring on July 18, 2018,
variable interest rate was a weighted average rate of 2.3603% at December 31, 2016
and 2.0742% at December 31, 2015
Total debt
Less current portion of long-term debt
Total long-term debt
2016
2015
$
11,400
$
11,400
8,600
8,600
78,000
98,000
8,600
89,400
$
90,000
110,000
—
110,000
$
Aggregate maturities required on long-term debt at December 31, 2016 are as follows:
2017
2018
Total
Revenue Bonds
$
$
8,600
89,400
98,000
The Variable Rate Demand Revenue Bonds are held by CINWYLLC. These revenue bonds require the Company to maintain
standby letters of credit totaling $20,333 at December 31, 2016. These letters of credit require compliance with certain
covenants, including minimum net worth, maximum debt to net worth, and interest coverage ratios. As of December 31,
2016, the Company was in compliance with these debt covenants.
Ciner Wyoming Credit Facility
On July 18, 2013, the Company entered into a $190,000 senior unsecured revolving credit facility, as amended on October
30, 2014 (as amended, the "Ciner Wyoming 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
15
fund working capital requirements, capital expenditures, to consummate permitted acquisitions and for all other lawful
Company 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 the Company 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. The Company's obligations under the Ciner Wyoming Credit Facility are
unsecured.
On May 25, 2016, Ciner Wyoming entered into a Second Amendment to the Credit Agreement, First Amendment to Notes
and First Amendment to Fee Letter (the “Ciner Wyoming Second Amendment”) with each of the lenders listed on the
respective signature pages thereof and Bank of America, N.A., as administrative agent, swing line lender and L/C issuer.
The Ciner Wyoming Second Amendment amends the Ciner Wyoming Credit Facility.
Among other things, the Ciner Wyoming Second Amendment (i) amends the Ciner Wyoming Credit Facility by modifying
the consolidated fixed charge coverage ratio (the ratio of consolidated cash flow to consolidated fixed charges, each as
defined in the Ciner Wyoming Credit Facility) from not less than 1.15 to 1.00, prior to the Ciner Wyoming Second Amendment,
to be not less than 1.00 to 1.00 as of the end of any fiscal quarter and (ii) prohibits financial institutions from European
Economic Area member countries from serving as loan parties under the Ciner Wyoming Credit Facility.
The Ciner Wyoming Credit Facility contains various covenants and restrictive provisions that limit (subject to certain
exceptions) the Company'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 the Company;
• merge or consolidate with another Company; and
•
transfer, sell or otherwise dispose of assets.
The Ciner Wyoming Credit Facility also requires quarterly maintenance of a leverage ratio (as defined in the Ciner Wyoming
Credit Facility) of not more than 3.00 to 1.00 and a fixed charge coverage ratio (as defined in the Ciner Wyoming Credit
Facility) of not less than 1.00 to 1.00. The Ciner Wyoming Credit Facility also requires that capital expenditures, as defined
in the Ciner Wyoming Credit Facility, not exceed $50,000 in any fiscal year.
In addition, 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 lenders may 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 CRC 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 the general partner of CINR (or any entity that performs the functions the general partner of
CINR). In addition, a change of control would be triggered if CINR ceases to own at least 50.1% of the economic interests
in the Company or cease to have the ability to elect a majority of the members of the Company's board of managers.
16
The Company was in compliance with all terms under its long-term debt agreements as of December 31, 2016.
Loans under the Ciner Wyoming Credit Facility bear interest at the Company'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
• a LIBOR Rate plus an applicable margin.
The unused portion of the Ciner Wyoming Credit Facility is subject to an unused line fee ranging from 0.275% to 0.350%
per annum based on the Company's then current consolidated leverage ratio.
Ciner Enterprises Credit Agreement
In addition, there are restrictions in the Ciner Enterprises Credit Agreement that affect the Company. Specifically, Ciner
Enterprises has agreed (subject to certain exceptions in addition to those described below) that it will not, and will not permit
any of its subsidiaries, including the Company to:
• make distributions on or redeem or repurchase equity interests, other than distributions to the Companies
members;
incur or guarantee additional debt, other than debt incurred under the Ciner Wyoming Credit Facility, among
•
certain other types of permitted debt;
• make certain investments and acquisitions, other than investments in the Company, in an amount not to exceed
$10,000 per calendar year and other exceptions set forth therein;
incur certain liens or permit them to exist, other than, with respect to the Companies liens, an aggregate amount
•
outstanding at any time equal to $1,000;
• enter into certain types of transaction with affiliates, other than transactions between Ciner Wyoming and CINR;
• merge or consolidate with another company; or
transfer, sell or otherwise dispose of assets, other than the Companies disposition of assets with a net book value
•
not to exceed $2,500, in any given year.
9. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities as of December 31, 2016 and 2015 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
Reclamation reserve at end of year
17
2016
2015
5,537
3,441
47
9,025
$
$
4,457
2,351
—
6,808
2016
2015
4,457
262
818
5,537
$
$
4,192
265
—
4,457
$
$
$
$
The reclamation adjustment above includes a new asset retirement obligation layer of $980 as of December 31, 2016, as a
result of the increase in the self-bond estimate. See Note 12 "Commitments and Contingencies" for additional information.
10. EMPLOYEE BENEFIT PLANS
The Company participates in various benefit plans offered and administered by CRC (administered by OCIE prior to the
Transaction) and is allocated its portions of the annual costs related thereto. The specific plans are as follows:
Retirement Plans - Benefits provided under the Ciner Pension Plan for Salaried Employees and Ciner Pension Plan for
Hourly Employees 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. CRC'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 net periodic pension cost was $2,015, $7,731 and $3,140 for
the years ended December 31, 2016, 2015 and 2014, respectively. The decrease in pension costs in 2016 was driven by lower
overall pension cost at the CRC level as a result of the retirement plans being fair valued in connection with Ciner Enterprises’
acquisition of CRC.
Savings Plan - The Ciner 401(k) Retirement 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. The Plan was amended such that 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 by the Company for the years ended December 31, 2016, 2015 and 2014 were $1,625, $2,582 and $2,428, respectively.
Postretirement Benefits - Most of the Company's employees are eligible for postretirement benefits other than pensions if
they reach retirement age while still employed.
CRC accounts for postretirement benefits on an accrual basis over an employee’s period of service. The postretirement plan,
excluding pensions, are not funded, and CRC has the right to modify or terminate the plan. Effective January 1, 2013, the
postretirement benefits for non-grandfathered retirees were amended to
replace the medical coverage for post-65-year-old members with a fixed dollar contribution amount. As a result of the
amendment, the accumulated and projected benefit obligation for CRC's postretirement benefits
decreased by approximately $8,700 and resulted in a prior service credit of approximately $7,700 which was recognized as
a reduction of net periodic postretirement benefit costs through year 2014. The post-retirement benefits had a benefits
obligation of $20,586 and $21,263 for the years ended December 31, 2016 and 2015, respectively. The Company's allocated
portion of postretirement benefit costs was expense of $1,400 and $495 for the years ended December 31, 2016 and December
31, 2015, respectively, and income of $260 the year ended December 31, 2014.
18
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss as of December 31, 2016, 2015 and 2014 consists of the following:
Interest
Rate Swap
Contract
Natural
Gas
Forwards
Contracts
Total
BALANCE at January 1, 2014
$
(550) $
— $
(550)
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive income/(loss)
BALANCE at December 31, 2014
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive income/(loss)
BALANCE at December 31, 2015
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive loss
Net current-period other comprehensive income/(loss)
BALANCE at December 31, 2016
(1,294)
1,096
(198
(748) $
.
(1,098)
1,027
—
—
—
(1,294)
1,096
(198)
— $
(748)
(3,722)
350
(4,820)
1,377
(71)
(3,372)
(3,443)
(819) $
(3,372) $
(4,191)
(401)
781
$
380
(544)
1,076
532
(945)
1,857
912
(439) $
(2,840) $
(3,279)
$
$
$
$
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:
2016
2015
2014
Affected Line Items
on the Statements of
Operations and
Comprehensive
Income
$
$
781
1,076
1,857
$
$
1,027
350
1,377
$
$
1,096
Interest expense
— Cost of Products Sold
1,096
Details about other comprehensive income/
(loss) components:
Gains and losses on cash flow hedges:
Interest rate swap contracts
Commodity hedge contracts
Total reclassifications for the period
12. COMMITMENTS AND CONTINGENCIES
The Company leases mineral rights from the U.S. Bureau of Land Management, the state of Wyoming, Rock Springs
Royalty Corp., a wholly owned subsidiary of Anadarko Holding Company (AHC), and other private parties. All of these
leases 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 intends to
continue renewing the leases as has been its practice.
19
The Company entered into a 10 year rail yard switching and maintenance agreement with a third party, Watco
Companies, LLC, 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 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. lease is perpetual. The Company has an option agreement with Watco to assign these leases to the
Company at any time during the land lease term.
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, 2016, the total minimum rental commitments under the Company’s various operating leases, including
renewal periods are as follows:
2017
2018
2019
2020
2021
2022 and thereafter
Total
Leased
Land
Track
Leases
Total
$
$
75
75
75
75
75
1,425
1,800
$
$
70
70
70
70
33
—
313
$
$
145
145
145
145
108
1,425
2,113
CRC, on behalf of the Company, 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. CRC's obligations related to these railcar leases are $12,484 in 2017, $11,345 in 2018, $10,396 in 2019, $7,777
in 2020, $5,215 in 2021 and $5,899 in 2022 and thereafter. Total lease expense was approximately $14,476, $12,415 and
$9,469 for the years ended December 31, 2016, 2015 and 2014, respectively.
Purchase Commitments - The Company has natural gas supply contracts to mitigate volatility in the price of natural gas. As
of December 31, 2016, these contracts totaled $77,063 for the purchase of a portion of our gas requirements over
approximately the next five years. The supply purchase agreements have specific commitments of $24,292 in 2017, $20,126
in 2018 $17,130 in 2019, $10,116 in 2019 and $5,399 in 2021. The Company has a separate contract that expires in 2021,
for transportation of natural gas with an average annual cost of approximately $3,946 per year.
Legal and Environmental - From time to time the Company is party to various claims and legal proceedings related to its
business. Although the outcome of these proceedings cannot be predicted with certainty, management does not currently
expect any of the legal proceedings the Company is involved in to have a material effect on its business, financial condition
and results of operations. The Company 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.
Off-Balance Sheet Arrangements - The Company has a self-bond agreement with the Wyoming Department of Environmental
Quality under which it commits to pay directly for reclamation costs at our Wyoming Plant site. As of December 31, 2016
and 2015, the amount of the bond was $38,200 and $33,875, respectively, 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.
20
13. AFFILIATES TRANSACTIONS
CRC is the exclusive sales agent for the Company and through its membership in ANSAC, CRC is responsible for promoting
and increasing the use and sale of soda ash and other refined or processed sodium products produced. All actual sales and
marketing costs incurred by CRC are charged directly to the Company. Selling, general and administrative expenses also
include amounts charged to the Company by CRC principally consisting of salaries, benefits, office supplies, professional
fees, travel, rent and other costs of certain assets used by the Company. In November 2016, CRC, on behalf of the Company,
entered into a soda ash sales agreement with CIDT, an affiliate of Ciner Group, that sells soda ash to markets not served by
ANSAC. The receivables associated with these sales are recorded in accounts receivable - other affiliate line item on the
consolidated balance sheet. These transactions do not necessarily represent arm's length transactions and may not represent
all costs if the Company operated on a standalone basis.
As a result of the closing of the Transaction discussed in Note 1 - "Corporate Structure," CINE owns indirectly and controls
the Company, therefore, OCIE and subsidiaries, including OCI Alabama LLC, are no longer related parties of the Company
as of the Transaction date. The following table includes transactions with OCIE and subsidiaries prior to the Transaction
date.
The total costs (recoveries) charged to the Company by affiliates for the years ended December 31, 2016, 2015 and 2014
are as follows:
OCI Enterprises Inc.
CRC
ANSAC (1)
CINR
Total selling, general and administrative expenses - affiliates
2016
2015
2014
— $
13,754
3,821
—
17,575
$
4,535
5,587
3,793
(11)
13,904
$
$
8,955
3,415
2,930
892
16,192
$
$
(1) ANSAC allocates its expenses to its members using a pro rata calculation based on sales.
Cost of products sold includes logistics services charged by ANSAC. For the years ended December 31, 2016, 2015 and
2014 these costs were $3,278, $8,134 and $9,194, respectively.
Net sales to affiliates for the years ended December 31, 2016, 2015 and 2014 are as follows:
ANSAC
CIDT
OCI Alabama LLC
Total
2016
262,220
9,054
—
271,274
$
$
2015
261,023
—
4,266
265,289
$
$
2014
230,762
—
5,923
236,685
$
$
As of December 31, 2016 and 2015, the Company had due from/to with affiliates as follows:
CINE
CRC
Ciner Resources Europe NV
Other
Total
2016
2015
Due from
Affiliates
Due to
Affiliates
Due from
Affiliates
Due to
Affiliates
— $
— $
3,932
2,230
137
6,299
$
1,670
—
2,537
4,207
$
25
6,942
4,814
544
12,325
$
$
—
1,888
—
2,746
4,634
$
$
21
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, 2016, 2015
and 2014 are as follows:
Domestic
International:
ANSAC
Other
Total international
Total net sales
15. SUBSEQUENT EVENTS
2016
192,550
262,220
20,417
282,637
475,187
$
$
2015
194,036
261,023
31,334
292,357
486,393
$
$
2014
194,801
230,762
39,469
270,231
465,032
$
$
On January 12, 2017, the members of the Board of Managers of Ciner Wyoming, approved a cash distribution to the members
in the aggregate amount of $25,000. The distribution was paid on February 6, 2017.
******
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UNITHOLDER INFORMATION
PARTNERSHIP
HEADQUARTERS
1201 Louisiana Street
Suite 3400
Houston, TX 77002
713.751.7507
REGIONAL OFFICES
Coal and Hard Minerals
5260 Irwin Road
Huntington, WV 25705
VantaCore
Headquarters
1600 Market Street
38th Floor
Philadelphia, PA 19103
INVESTOR RELATIONS
Kathy Roberts
1201 Louisiana Street
Suite 3400
Houston, TX 77002
713.751.7555
Email: kroberts@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
WEBSITE
www.nrplp.com
Information regarding Natural Resource Partners L.P. is located on the partnership’s website.
On the site is operational and financial information as well as all SEC filings and our corporate
governance documents, including our Code of Business Conduct and Ethics, our Corporate
Governance Guidelines and Board of Directors’ Audit Committee Charter. Requests for copies
of the annual report or other data may be made through the website or by contacting Investor
Relations. These requests will be provided free of charge.
CONTACT NRP BOARD
We have established procedures for contacting the non-management members of the NRP Board
of Directors. To communicate any concerns or issues to the Board of Directors, please direct any
correspondence to:
Chairman of the CNG Committee
NRP Board of Directors
1201 Louisiana Street, Suite 3400
Houston, TX 77002
888.252.2396
SCHEDULE K-1
Unitholders receive Schedule K-1 packages that summarize their 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, soda ash and aggregates 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.
Natural Resource Partners L.P.
1201 Louisiana Street, 34th Floor
Houston, Texas 77002
www.nrplp.com
FSC