A DIVERSIFIED
NATURAL
RESOURCE
COMPANY
Natural Resource Partners L.P.
2014 Annual Report
INTERESTS IN
GREATER THAN
1,500
OIL AND
GAS WELLS
2.3
BILLION
TONS
OF COAL
RESERVES
WHAT WE O
49%
EQUITY INTEREST
IN TRONA MINING
AND SODA ASH
PROCESSING
COMPANY
792
MILLION TONS
OF AGGREGATES
IN 16 STATES
WN
In recent years, Natural Resource Partners has
focused on a business plan designed to diversify
our asset base and revenue streams. With prudent,
accretive acquisitions beyond the coal space, we have
successfully transitioned into a diverse, more balanced
natural resource company with strong positions in
sectors that supply America with energy, electricity,
construction materials, and essential products.
1
AGGREGATES
COAL
AGGREGATES – CRUSHED STONE, SAND AND
GRAVEL – ARE USED IN THE MAJORITY OF THE
COUNTRY’S INFRASTRUCTURE.
400
TONS
It takes 400 tons of aggregates to
build the typical modern home.
94%
AND
80%
Aggregates make up 94 percent
of asphalt pavement and 80 percent
of concrete.
COAL IS ONE OF THIS NATION’S MOST ABUNDANT
FUEL SOURCES AND IS USED PRIMARILY FOR
GENERATION OF ELECTRICITY, AND IS ALSO USED
IN PRODUCING STEEL USED IN BUILDING THE
NATION’S INFRASTRUCTURE.
39%
In 2014, coal provided 39 percent of total
U.S. electricity generation.
1:3
Each person in the United States uses
three tons of coal every year.
917
MM TONS
Nearly 917 million tons of coal used
annually in the United States.
152,000
TONS
It takes 152,000 tons of aggregates
to build one mile of a four-lane
interstate highway.
WHY IT’S IM
2
SODA ASH
OIL AND GAS
WHILE OIL IS PRIMARILY USED FOR FUELING THE
NATION’S AUTOMOBILES, TRUCKS AND TRANS-
PORTS, GAS IS USED PRIMARILY IN GENERATING
ELECTRICITY AND HEATING OUR HOMES.
SODA ASH CONSUMPTION TENDS TO INCREASE
IN PROPORTION TO POPULATION AND GROSS
DOMESTIC PRODUCT GROWTH RATES.
19.05
MILLION
In 2014, the United States consumed
an average of 19.05 million barrels of
petroleum products per day.
47%
47 percent of U.S. soda ash used in
making glass.
30%
30 percent of U.S. soda ash used
in chemicals.
7%
7 percent of U.S. soda ash used in soaps
and detergents.
92%
Oil accounts for 92 percent of the
energy used for transportation in
the United States.
200
The average U.S. home uses
200 cubic feet of natural gas every day.
PORTANT
3
Learn more about our recent
acquisitions and how they
add value to the company.
(cid:98)
VantaCore Acquisition
VantaCore is one of the top
25 aggregates producers in
the country. It controls almost
300 million tons of estimated
reserves in five states, and
will facilitate our growth in the
construction aggregates business.
Williston Basin
We acquired oil and gas assets
in the Sanish Field, one of the
nation’s premier producing regions.
They include 6,086 net acres
and 196 producing wells at
December 31, 2014.
To Our Unitholders
Although 2014 was a challenging year by virtually any standard,
Natural Resource Partners remained focused on executing a
business plan designed to diversify our asset base, revenue
streams, and cash flow. Even in an uncertain energy environ-
ment, we reinforced our commitment to that strategy with
two transformative acquisitions beyond the coal space – one
in aggregates, the other in oil and gas – that are expected to
deliver long-term value to our unitholders.
Even In A Challenging Market, Continued Diversification
In 2014, Natural Resource Partners continued to manage the tremendous challenges
that accompany a turbulent commodity price environment. Our ability to move
forward even in difficult times has helped to further establish us as a diversified
natural resources company that is built for the long term. As evidence of our
continued diversification:
• Total revenues and other income rose 12 percent, to $399.8 million, because of
significant increases in revenue from aggregates and oil and gas assets, and from
equity income from our soda ash business
• Approximately $173 million, or 43 percent, of our revenues and other income were
attributable to non-coal-related assets
These increases have helped cushion us from an uncertain coal market and enabled
us to offset continued declines in coal-related income.
Last year, we undertook two major transactions that both complemented our existing
assets and are expected to deliver positive long-term value for our unitholders: the
purchase of VantaCore Partners LLC, which specializes in the construction materials
industry; and the acquisition of non-operated working interests in oil and gas properties
in the Bakken/Three Forks play of the Williston Basin from an affiliate of Kaiser-Francis
Oil Co.
VantaCore
VantaCore is one of the top 25 aggregates producers in the United States, controlling
approximately 292 million tons of estimated reserves across five states. It operates
three hard rock quarries, six sand and gravel plants, two asphalt plants, and a marine
terminal. It was originally formed to acquire stable, well-managed companies and
since 2006 has successfully integrated seven such companies. With an experienced
management team in place, we believe that VantaCore will facilitate future growth in
the construction aggregates business. In the fourth quarter of 2014 we recorded total
revenues of $137.3 million compared with $94.7 million during the same period in
2013, an increase due largely to VantaCore’s contributions.
4
“ Our confidence is built in part on the belief
that, in many ways, Natural Resource
Partners is helping to supply America with
what Americans have always needed...”
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
5
Financial Highlights
(in millions, except per unit)
2014
2013
2012
2011
2010
2009
2008
2007
FOR THE YEAR ENDED DECEMBER 31
Total Revenues
$
400
$
Income from operations
Net income
Net income before
189
109
358
236
172
$
379
$
378
$
301
$
256
$
292
$
267
213
104
54
196
154
154
114
197
170
considering impairments
135
173
216
215
154
114
170
215
128
102
102
Net income per unit
$
.94
$ 1.54
$ 1.97
$
.50
$
1.54
$
1.17
$
1.95
$
1.11
Net income per unit before
considering impairments
$
1.17
$
1.55
$
2.00
Distributions per unit
$ 1.40
$ 2.00
$ 2.20
$
$
1.99
2.18
$
$
1.54
2.16
$ 1.17
$ 1.95
$
1.11
$ 2.16
$ 2.07
$ 1.88
Weighted average number
of units outstanding
113
110
106
106
82
68
65
65
Cash from operations
$
211
$
247
$
271
$
306
$
259
$
211
$
230
$
168
BALANCE SHEET DATA
(at December 31)
Cash and cash equivalents
$
50
$
93
$
149
$
215
$
96
$
83
$
90
$
58
Total assets
Long-term debt
Partner’s capital
2,445
1,992
1,765
1,666
1,664
1,524
1,301
1,320
1,394
1,084
720
617
897
617
836
645
661
825
627
765
479
743
496
745
07
08
09
10
11
12
13
14
$256
$292
$301
$215
6
Total Revenue
(cid:79) Coal
(cid:79) Aggregates
(cid:79) Oil & Gas
(cid:79) Industrial Minerals
(cid:79) Other
$ in millions
$378
$379
$358
$400
Williston Basin
Our acquisition in the Williston Basin is located in the Sanish Field in North Dakota,
one of the premier, most prolific oil producing regions in the country. It includes
over 6,000 net acres and 196 producing wells at year-end. This acquisition added
to our existing non-operated working interest assets in the Williston Basin and will
be easily integrated into our current operations.
Looking Forward: Prepared For The Challenges
While we have acquired some high-quality long-term assets for our unitholders, our
debt level following those acquisitions is higher than we would like. As a result, we
have implemented a long-term strategic plan that will help to strengthen our balance
sheet and put us in a position to capitalize on future opportunities to expand our
existing asset platforms. After several years of accelerated growth and diversifica-
tion of assets through acquisitions, we will concentrate in 2015 on implementing our
long-term plan to strengthen our balance sheet, reduce debt, and enhance liquidity.
As part of our plan, we will increase our focus on capital efficiency and maintain our
ongoing diversification strategy through organic growth of our aggregates, industrial
minerals, and oil and natural gas assets. As we look ahead to the future, we do so
with confidence but recognize the challenges that lie ahead.
Our confidence is built in part on the belief that, in many ways, Natural Resource
Partners is helping to supply America with what Americans have always needed:
coal for electricity; oil and gas for energy; raw materials for essential products like
glass, chemicals, soap, and paper; and the aggregates necessary to build and rebuild
the nation’s infrastructure, and to develop new residential and commercial structures.
As America continues to grow, so too will the demand for our products.
Thanks to a forward-looking long-term strategy and a management team committed
to executing effectively, we have transformed into a diverse natural resource
company. As such, we are fully prepared to overcome any challenge and maximize
any opportunity that the future may hold.
Learn more about our
enduring value.
(cid:98)
2014 Highlights
• Revenues and other income
increased 12 percent
• 43 percent of revenues and
other income attributable
to non-coal-related assets
• Transformative acquisitions
that strengthened our
position in the oil and gas
and aggregates sectors
• Successful transition into a
diversified natural resource
company with a diverse
range of assets
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
7
Stephen P. Smith (1) (3) (4)
NiSource, Inc.
Executive Vice President and Chief Financial Officer
General partner of Columbia Pipeline Partners LP
Chief Financial Officer, Chief Accounting Officer
and Board Member
Leo A. Vecellio, Jr. (2) (4)
Vecellio Group, Inc.
Chairman and Chief Executive Officer
OFFICERS
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
Kevin J. Craig
Executive Vice President – Coal
Dennis F. Coker
Vice President – Aggregates
David Hartz
Vice President – Oil and Gas
Kathy H. Roberts
Vice President – Investor Relations
Kathryn S. Wilson
Vice President, General Counsel and Secretary
Gregory F. Wooten
Vice President – Chief Engineer
Christopher J. Zolas
Chief Accounting Officer
Directors & Officers
BOARD OF DIRECTORS
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
Robert T. Blakely (1) (2) (3) (4)
Ally Financial
Chairman of the Audit Committee
Greenhill & Co.
Westlake Chemical Corporation
Board Member
Russell D. Gordy (2) (4)
SG Interests, RGGS and Rock Creek Ranch
Managing Partner
Gordy Oil Company and Gordy Gas Corporation
President
Donald R. Holcomb
Dickinson Fuel Company, Inc.
Chief Executive Officer
Dickinson Properties Limited Partnership
Managing General Partner
Ikes Fork, LLC
Owner and Manager
Robert B. Karn III (1) (2) (3) (4)
Peabody Energy Corporation
Kennedy Capital Management, Inc.
Board Member
Guggenheim family of funds – numerous publicly
listed closed-end and exchange traded funds
Board of Trustees Member
S. Reed Morian
DX Holding Company
Chairman, Chief Executive Officer and President
Richard A. Navarre (1) (4)
Civeo Corporation
Chairman of the Audit Committee
Secure Energy, LLC
Advisory Board Member
Corbin J. Robertson III
LKCM Headwater Investments GP, LLC
Co-Managing Partner
General partner of Genesis Energy L.P.
Corsa Coal Corp
Buckhorn Energy Services
LL&B Minerals
Board Member
(1) Audit Committee
(2) Nominating and Compensation Committee
(3) Conflicts Committee
(4) Independent Directors
8
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
È
‘
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014 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)
601 Jefferson, Suite 3600
Houston, Texas
(Address of principal executive offices)
35-2164875
(I.R.S. Employer
Identification Number)
77002
(Zip Code)
(713) 751-7507
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Units representing limited partnership interests
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 È
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 È
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 È
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 È 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.
È 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 È
The aggregate market value of the Common Units held by non-affiliates of the registrant (treating all executive officers
and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they were
affiliates of the registrant) was approximately $1.3 billion on June 30, 2014 based on a price of $16.57 per unit, which was
the closing price of the Common Units as reported on the daily composite list for transactions on the New York Stock
Exchange on that date.
As of February 27, 2015, there were 122,299,825 Common Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE.
None.
Item
Table of Contents
PART I
1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.
PART II
5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of
Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.
7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . .
7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8.
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . .
9.
9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9B. 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Exhibits, Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.
11.
12.
13.
14.
15.
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Forward-Looking Statements
Statements included in this Annual Report on Form 10-K may constitute forward-looking statements. In
addition, we and our representatives may from time to time make other oral or written statements which are also
forward-looking statements.
Such forward-looking statements include, among other things, statements regarding:
• our business strategy;
• our financial strategy;
• prices of and demand for coal, oil, natural gas, aggregates and industrial minerals;
• estimated revenues, expenses and results of operations;
• the amount, nature and timing of capital expenditures;
• our ability to make acquisitions and integrate the acquisitions we do make;
• our liquidity and access to capital and financing sources;
• projected production levels by our lessees, VantaCore Partners LLC, and the operators of our oil and gas
working interests;
• OCI Wyoming LLC’s 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 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. 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.
1
PART I
As used in this Part I, unless the context otherwise requires: “we,” “our” and “us” 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 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.
Item 1. Business
We are a limited partnership formed in April 2002, and we completed our initial public offering in October
2002. We engage 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, crude oil and natural gas,
construction aggregates, frac sand and other natural resources. Executing on our plans to diversify our business,
we have completed over $900 million in acquisitions since January 2013. For the year ended December 31, 2014,
we recorded revenues and other income of $399.8 million and Adjusted EBITDA of $300.3 million.
Approximately $226.7 million (57%) of our 2014 revenues and other income were attributable to coal-related
sources, and $173.0 million (43%) of our revenues and other income were attributed to non-coal-related sources.
Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income,
see “Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA.”
Our coal reserves are located in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin
and the Western United States, as well as lignite reserves in the Gulf Coast region. 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. We also own and manage infrastructure
assets that generate additional revenues, primarily in the Illinois Basin.
We own or lease 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. However, the majority of
our aggregates and industrial mineral revenues come from VantaCore Partners LLC, which we acquired in
October 2014. VantaCore specializes in the construction materials industry and operates three hard rock quarries,
five sand and gravel plants, two asphalt plants and a marine terminal. VantaCore’s current operations are located
in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
We own a 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the
Green River Basin, Wyoming. OCI 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.
We own various interests in oil and gas properties that are located in the Williston Basin, the Appalachian
Basin, Louisiana and Oklahoma. Our interests in the Appalachian Basin, Louisiana and Oklahoma are minerals
and royalty interests, while in the Williston Basin we own non-operated working interests. Our Williston Basin
non-operated working interest properties include the properties acquired in the Sanish Field from an affiliate of
Kaiser-Francis Oil Company in November 2014.
Partnership Structure and Management
Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We conduct
our business through two wholly owned operating companies: NRP (Operating) LLC and NRP Oil and Gas LLC.
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
2
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, Mr. Robertson is entitled to
nominate ten directors, five of whom must be independent 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.
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 several 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 601 Jefferson Street, Suite 3600, Houston, Texas 77002 and our phone number is
(713) 751-7507.
Coal and Coal-Related Properties
Coal Royalty Business
Royalty businesses principally own and manage mineral reserves. As an owner of coal reserves, we
typically are not responsible for operations on our coal properties, but instead enter into leases with operators
granting them the right to mine and sell reserves from our property in exchange for a royalty payment. 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.
Under our standard lease, lessees calculate royalty payments due to us and are required to report tons of coal
removed as well as the sales prices of the extracted coal. 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 monthly,
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. Our current coal royalty leases provide for the payment of approximately $103
million in minimums to us during 2015.
Because we do not operate any coal mines, our coal royalty business does not bear ordinary operating costs
and has limited direct exposure to environmental, permitting and labor risks. As operators, our lessees are subject
to environmental laws, permitting requirements and other regulations adopted by various governmental
authorities. In addition, the lessees generally bear all labor-related risks, including retiree health care legacy
costs, black lung benefits and workers’ compensation costs associated with operating the mines on our coal and
aggregates properties. We typically pay property taxes on our properties, which are then reimbursed by the lessee
pursuant to the terms of the lease.
3
Coal Royalty Revenues, Reserves and Production
The following summary table sets forth coal royalty revenues and average coal royalty per ton from the
properties that we owned or controlled for the years ending December 31, 2014, 2013 and 2012. Coal royalty
revenues were generated from the properties in each of the areas as follows:
Coal Royalty Revenues
Average Coal Royalty Per Ton
Year Ended December 31,
Year Ended December 31,
2014
2013
2012
2014
2013
2012
(In thousands)
($ per ton)
Area
Appalachia:
Northern . . . . . . . . . . . . . . . . . . . . . . .
Central
. . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . .
$ 8,621
89,627
20,292
$ 14,643
105,004
26,156
$ 15,768
156,390
29,325
Total Appalachia . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast
118,540
54,049
7,804
3,793
145,803
56,001
7,569
3,290
201,483
49,538
8,501
1,212
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$184,186 $212,663 $260,734
$0.92
$4.46
$5.18
$3.55
$4.10
$2.74
$3.47
$3.65
$1.27
$5.05
$6.30
$4.00
$4.28
$2.72
$3.39
$3.99
$1.50
$5.99
$7.89
$5.00
$4.38
$3.58
$2.60
$4.79
The following summary table sets forth coal production data and reserve information for the properties that
we owned or controlled for the years ending December 31, 2014, 2013 and 2012. All of the reserves reported
below are recoverable reserves as determined by the SEC’s Industry Guide 7. In excess of 90% of the reserves
listed below are currently leased to third parties. Coal production data and reserve information for the properties
in each of the areas are as follows:
Coal Production and Reserves
Production for Year Ended
December 31,
Proven and Probable Reserves at
December 31, 2014
2014
2013
2012
Underground
Surface
Total
(Tons in thousands)
Area
Appalachia:
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,339
11,505 10,486
20,092 20,801 26,098
3,718
4,151
3,914
469,206
1,017,993
83,846
27,864
497,070
260,598 1,278,591
108,576
24,730
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33,345 36,457 40,302
13,177 13,087 11,299
2,377
2,778
2,844
466
970
1,093
1,571,045
330,137
313,192 1,884,237
345,162
15,025
94,157
— 94,157
2,696
2,696
—
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50,459 53,292 54,444
1,901,182
425,070 2,326,252
We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with
a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%.
Compliance coal is coal which meets the standards of Phase II of the Clean Air Act and is that portion of low
sulfur coal that, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu. As of December 31,
2014, approximately 49% of our reserves were low sulfur coal and 32% of our reserves were compliance coal.
Unless otherwise indicated, we present the quality of the coal throughout this Annual Report on Form 10-K on an
as-received basis, which assumes 6% moisture for Appalachian reserves, 12% moisture for Illinois Basin
4
reserves and 25% moisture for Northern Powder River Basin reserves. We own both steam and metallurgical coal
reserves in Northern, Central and Southern Appalachia, as well as the Gulf Coast, and we own steam coal
reserves in the Illinois Basin and the Northern Powder River Basin. In 2014, approximately 32% of the
production and 40% of the coal royalty revenues from our properties were from metallurgical coal.
The following table sets forth our estimate of the sulfur content, the typical quality of our coal reserves and
the type of coal in each area as of December 31, 2014.
Sulfur Content, Typical Quality and Type of Coal
Sulfur Content
Typical Quality
Type of Coal
Compliance
Coal(1)
Low
(<1.0%)
Medium
(1.0%
to
1.5%)
High
(>1.5%)
Total
Heat
Content
(Btu per
pound)
Sulfur
(%)
(Tons in thousands)
Steam
Met(2)
(Tons in thousands)
Area
Appalachia
Northern . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
Central
Southern . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . .
Northern Powder River Basin . . .
. . . . . . . . . . . . . . . . . .
Gulf Coast
50,097
623,881
72,273
746,251
—
—
96
24,466 399,788
72,816
885,689 332,186
27,499
78,337
497,070 12,831
60,716 1,278,591 13,311
108,576 13,509
2,740
1,036,842 384,151 463,244 1,884,237 13,196
345,162 11,497
8,800
6,922
— 2,183 342,979
—
—
— 94,157
2,696
—
94,157
2,696
2.58
0.90
0.84
487,508
9,562
858,899 419,692
29,986
78,590
1.34 1,424,997 459,240
—
345,162
3.28
—
94,157
0.65
96
2,600
0.69
Total . . . . . . . . . . . . . . . . . . . . . . .
746,347
1,133,695 386,334 806,223 2,326,252
1,866,916 459,336
(1) Compliance coal 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.
(2) 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.
We have engaged outside consultants to conduct reserve studies of our existing properties. These studies are
an ongoing process and we will update the reserve studies based on our review of the following factors: the size
of the properties, the amount of production that has occurred, or the development of new data which may be used
in these studies. In connection with most acquisitions, we have either commissioned new studies or relied on
recent reserve studies completed prior to the acquisition. In addition to these studies, we base our estimates of
reserve information on engineering, economic and geological data assembled and analyzed by our internal
geologists and engineers. 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.”
5
Major Coal 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 2014, 6.0 million tons
were produced from the property by Consolidation Coal Company. 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. Coal is shipped by rail to utility customers such as First Energy and PPL.
Beaver Creek.
The Beaver Creek property is located in Grant and Tucker Counties, West Virginia. In
2014, 1.4 million tons were produced from this property. We lease this property to Mettiki Coal, LLC, a
subsidiary of Alliance Resource Partners L.P. Coal is produced from an underground longwall mine and is
transported by truck to a preparation plant operated by the lessee. Coal is shipped primarily by truck to the Mount
Storm power plant of Dominion Power.
AFG-Ohio.
The AFG-Ohio property is located in Belmont County, Ohio. In 2014, 1.4 million tons were
produced from the property. We lease this property to subsidiaries of Murray Energy Corporation. Coal is
produced from an underground longwall mine and shipped by rail and barge to customers including AEP, Duke
Energy and First Energy.
6
The map below shows the location of our properties in Northern Appalachia.
7
Central Appalachia
VICC/Alpha. The VICC/Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties,
Virginia. In 2014, 3.8 million tons were produced from this property. We primarily lease this property to a
subsidiary of Alpha Natural Resources, Inc. Production comes from both underground and surface mines and is
trucked to one of four preparation plants. Coal is shipped via both the CSX and Norfolk Southern railroads to
utility and metallurgical customers. Major customers include American Electric Power, Southern Company,
Tennessee Valley Authority, VEPCO and U.S. Steel and to various export 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 Patriot Coal Corporation. In 2014,
2.9 million tons were produced from the property. Both steam and metallurgical coal are produced from
underground and surface mines and has been historically transported by belt or truck to preparation plants on the
property. Coal is shipped via the CSX railroad to steam customers such as American Electric Power, Dayton
Power and Light, Detroit Edison and to various export metallurgical customers.
Pinnacle. The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. In 2014,
2.4 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 Cliffs Natural Resources, Inc. 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.
Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2014, 2.1 million tons
were produced from this property. We primarily lease the property to a subsidiary of Alpha Natural Resources,
Inc. Production comes from both underground and surface mines. This property has the ability to ship coal on
both the CSX and Norfolk Southern railroads.
VICC/Kentucky Land. The VICC/Kentucky Land property is located primarily in Perry, Leslie and Pike
Counties, Kentucky. In 2014, 1.7 million tons were produced from this property. Coal is produced from a number
of lessees, including subsidiaries of TECO and Blackhawk Mining, from both underground and surface mines.
Coal is shipped primarily by truck but also on the CSX and Norfolk Southern railroads to customers such as
Southern Company, Tennessee Valley Authority, and American Electric Power.
Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. In 2014, 1.4 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 utility and metallurgical customers such as
SCANA and US Steel.
Kingston. The Kingston property is located in Fayette and Raleigh Counties, West Virginia. This property
is leased to a subsidiary of Alpha Natural Resources, Inc. In 2014, 1.1 million tons were produced from the
property. Both steam and metallurgical coal are produced from underground and surface mines and has been
historically transported by belt or truck to a preparation plant on the property or shipped raw. During 2014, the
lessee idled the surface mines on the property in response to market conditions. Coal is shipped via both the CSX
railroad and by truck to barges to steam customers and various export metallurgical customers.
D.D. Shepard. The D.D. Shepard property is located in Boone County, West Virginia. This property is
primarily leased to a subsidiary of Patriot Coal Corporation. In 2014, 641,000 tons were produced from the
property. Both steam and metallurgical coal are produced by the lessees from underground and surface mines.
Coal is transported from the mines via belt or truck to preparation plants on the property. Coal is shipped via the
CSX railroad to various domestic and export metallurgical customers.
Pardee. The Pardee property is located in Letcher County, Kentucky and Wise County, Virginia. In 2014,
512,000 tons were produced from this property. We lease the property to a subsidiary of Arch Coal, Inc. and
Revelation Energy. In late 2014, Arch surrendered the surface mineable coal on the lease and we entered into a
8
new lease for those reserves with Revelation Energy. Production comes from underground mines and is
transported by truck or beltline to a preparation plant on the property and shipped on the Norfolk Southern
railroad primarily to domestic and export metallurgical customers such as Algoma Steel and Arcelor.
The map below shows the location of our properties in Central Appalachia.
9
Southern Appalachia
Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2014, 2.4 million tons
were produced from this property. We lease the property to a subsidiary of Cliffs Natural Resources, Inc.
Production comes from an underground mine and is transported primarily by beltline to a preparation plant. The
metallurgical coal is then shipped via railroad and barge to both domestic and export customers.
BLC Properties. The BLC properties are located in Kentucky and Tennessee. In 2014, 1.5 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. Major
customers include South Carolina Electric & Gas, and numerous medium and small industrial customers.
The map below shows the location of our properties in Southern Appalachia.
10
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 2014, 6.0 million tons were mined on the
property. This production is from a longwall mine and is shipped primarily via the Canadian National railroad to
customers such as Duke Energy and to various export customers.
Hillsboro. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. The property is
under lease to a subsidiary of Foresight Energy LP, and in 2014, 5.4 million tons were shipped from the property.
Production is currently 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.
Macoupin. The Macoupin property is located in Macoupin County, Illinois. The property is under lease to
a subsidiary of Foresight Energy LP, and in 2014, 1.1 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
customers such as Western KY Energy and other midwest utilities or loaded into barges for shipment to export
customers.
Sahara. The Sahara property is located in Saline, Hamilton and Williamson Counties in Illinois. This
property was acquired in June of 2014. The property is under lease to a subsidiary of Peabody Energy
Corporation, and following the acquisition in 2014, 486,000 tons were mined on the property. Production is
currently from an underground mine and is shipped via barge primarily to Tennessee Valley Authority.
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 LP. See
“—Coal Transportation and Processing Assets.”
11
The map below shows the location of our properties in the Illinois Basin.
12
Northern Powder River Basin
Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In
2014, 2.8 million tons were produced from our property. A subsidiary of Westmoreland Coal Company has two
coal leases on the property. 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 properties in the Northern Powder River Basin.
13
Coal Transportation and Processing Assets
We own preparation plants and related material handling facilities that we lease to third parties. Similar to
our royalty structure, the throughput fees for the use of these facilities are based on a percentage of the ultimate
sales price for the material that is processed.
In addition to our preparation plants, we own handling and transportation infrastructure related to certain of
our coal and aggregates 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 operated by an affiliate of Foresight Energy. While we own coal reserves at
the Williamson and Macoupin mines, we do not own coal reserves at the Sugar Camp mine. We typically lease
this infrastructure to third parties and collect throughput fees; however, at the loadout facility at the Williamson
mine in Illinois, we operate the coal handling and transportation infrastructure and have subcontracted out that
responsibility to a third party.
Total revenues from our coal transportation and processing assets were $22.0 million for the year ended
December 31, 2014.
Aggregates and Industrial Minerals Business
Aggregates are crushed stone, sand and gravel, utilized in the construction of the majority of our country’s
infrastructure. Aggregates are used in nearly every residential, commercial and building construction project and
in most public works projects, such as roads, highways, bridges, railroad beds, dams, airports, water and sewage
treatment plants and systems and tunnels. Through our subsidiary, VantaCore Partners LLC, we mine and
produce construction materials. In addition, we own aggregates reserves throughout the United States, a portion
of which are leased to third parties in exchange for royalty payments.
Industrial minerals include non-fuel mineral resources such as soda ash, sand, lime, potash and rare earths,
among others, that are mined and processed for a wide range of industrial and consumer applications such as
glass, abrasives, soaps and detergents. We own a 49% noncontrolling equity interest in OCI Wyoming’s trona
mining and soda ash production operation.
14
VantaCore Partners LLC Construction Materials Business
VantaCore is a construction materials company that we acquired on October 1, 2014. VantaCore operates
three limestone quarries, five sand and gravel plants, two asphalt plants and a marine terminal. VantaCore is
headquartered in Philadelphia, Pennsylvania, and its operations are located in Pennsylvania, West Virginia,
Tennessee, Kentucky and Louisiana. As of December 31, 2014, VantaCore controlled approximately 292 million
tons of estimated aggregates reserves. The reserve estimates for each of VantaCore’s properties were prepared
internally and audited by an independent third party advisor. For the three months ended December 31, 2014,
VantaCore sold approximately 1.9 million tons of crushed stone and gravel, including brokered stone, 0.4 million
tons of sand and 40,000 tons of asphalt. VantaCore’s three operating businesses are Laurel Aggregates, located in
Lake Lynn, Pennsylvania, Winn Materials/McIntosh Construction, located near Clarksville, Tennessee, 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.
Laurel Aggregates
Nashville
Baton Rouge
Pittsburgh
Winn Materials
Southern Aggregates
Laurel Aggregates
Laurel Aggregates is a limestone mining company located in Lake Lynn, Pennsylvania. Its operations
consist of a surface mine and an underground mine 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 primarily of oilfield service companies
and natural gas exploration and production companies and also include 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 and around Clarksville, Tennessee, which is
located approximately 45 miles northwest of Nashville and is Tennessee’s fifth largest city.
15
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 and 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.
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, and the waste is 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 based on its sales volumes.
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.
Trona Mining and Soda Ash Production Business
We own a 49% non-controlling equity interest in OCI Wyoming LLC (“OCI 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. OCI 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 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.
OCI 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. OCI 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.
16
The following map provides an aerial view of OCI Wyoming’s surface operations.
In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering the
liquor, a solution consisting of sodium carbonate dissolved in water. OCI 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 seven on-site
storage silos to await shipment by bulk rail or truck to distributors and end customers. OCI 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.
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. OCI Wyoming’s deca rehydration process enables OCI 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, OCI Wyoming
has been able to reduce the amount of short tons of trona ore it takes to produce one short ton of soda ash.
The soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended
December 31, 2014, OCI Wyoming shipped approximately 96.0% 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. OCI Wyoming leases a fleet of more than 1,700 hopper cars that serve as
dedicated modes of shipment to its domestic customers. For export, OCI 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
17
Corporation (“ANSAC”) provides logistics and support services for all of OCI Wyoming’s export sales. For
domestic sales, OCI Chemical Co. provides similar services.
OCI Wyoming’s largest customer is ANSAC, which buys soda ash (through OCI Wyoming’s sales agent)
and other of its member companies for further export to its customers. 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, OCI Chemical, on OCI Wyoming’s behalf, negotiates directly with, and OCI Wyoming exports to,
customers in markets not served by ANSAC.
OCI Wyoming is party to nine mining leases and one license for its subsurface mining rights. Some of the
leases are renewable at OCI Wyoming’s option upon expiration. OCI Wyoming pays royalties to the State of
Wyoming, the U.S. Bureau of Land Management and Anadarko Petroleum or its affiliates, 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 OCI Wyoming is obligated
to pay minimum royalties or annual rentals to its lessors and licensor regardless of actual sales. The royalty rates
paid to OCI Wyoming’s lessors and licensor may change upon renewal of such leases and license.
As a minority interest owner in OCI Wyoming, we do not operate and are not involved at all in the day-to-
day operation of the trona ore mine or soda ash production plant. Our partner, OCI Resources LP manages the
mining and plant operations. We appoint three of the seven members of the Board of Managers of OCI Wyoming
and have certain limited negative controls relating to the company.
Aggregates/Industrial Minerals Royalty Business
We own an estimated 500 million tons of aggregates reserves located in a number of states across the
country. We lease a portion of these reserves to third parties in exchange for royalty payments. The structure of
these leases is similar to our coal leases, and these leases typically also require minimum rental payments in
addition to royalties. See “—Coal and Coal-Related Properties—Coal Royalty Business” for a description of our
royalty structure. In 2006, we bought our first aggregates reserves property on the Puget Sound in Washington
State. Since that time, we have made several other aggregates reserve purchases in multiple U.S. geographies.
During 2014, our aggregates lessees produced 3.5 million tons of aggregates from these properties and we
received $8.7 million in aggregates royalty revenues, including overriding royalty revenues.
Oil and Natural Gas Properties
We generate oil and gas revenues from non-operated working interests, royalty interests and overriding
royalty interests in producing oil and gas wells. During 2014, we generated $59.6 million in revenues from our
interests in oil and gas properties. Our primary interests in oil and natural gas producing properties are our non-
operated working interests located in the Williston Basin, but we also own fee mineral, royalty or overriding
royalty interests in oil and gas properties in several other areas, including the Appalachian Basin and the
Mississippian Lime formation. NRP owns a 51% interest in BRP LLC, which owns oil and gas mineral rights, in
northern Louisiana. See “—BRP LLC Joint Venture.”
Revenues related to our non-operated working interests in oil and gas assets are recognized on the basis of
our net revenue interests in hydrocarbons produced. We also incur capital expenditures and operating expenses
associated with the non-operated working interests. Oil and gas royalty revenues include production payments as
well as bonus payments and are recognized on the basis of hydrocarbons sold by lessees and the corresponding
revenues from those sales. Generally, the lessees make payments based on a percentage of the selling price.
Some leases are subject to minimum annual payments or delay rentals. Our revenues fluctuate based on changes
in the market prices for oil and natural gas, the decline in production from producing wells, and other factors
affecting the third-party oil and natural gas exploration and production companies that operate our wells,
including the cost of development and production.
18
Our non-operated working interests are all located in the Williston Basin in North Dakota and Montana. As
of December 31, 2014, we had non-operated working interests in 21,832 net acres in the basin, all of which are
held by production. These assets include 6,086 net acres in the Sanish Field in Mountrail County, North Dakota
that we acquired in November 2014 from an affiliate of Kaiser-Francis Oil Company. The interests acquired in
that acquisition are all operated by Whiting Petroleum Corporation and include an estimated average working
interest of 14.5% in approximately 196 wells that were producing as of December 31, 2014.
We own royalty interests where we have leased certain portions of our owned mineral interests to third
parties primarily located in the southern portion of the Appalachian Basin and in the Mississippian Lime in
Oklahoma. We also own overriding royalty interests primarily located in the Appalachian Basin in West Virginia
and Pennsylvania, including in the Marcellus Shale, and in the Haynesville Shale in Louisiana.
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. Our estimated proved reserves as of December 31, 2014
were prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineer. To achieve
reasonable certainty, Netherland Sewell employed technologies that have been demonstrated to yield results with
consistency and repeatability. The technologies and economic data used in the estimation of our 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 following tables set forth our estimated proved and related standardized measure of discounted cash
flows by reserve category as of December 31, 2014. Netherland Sewell prepared its report covering properties
representing 100% of our estimated proved reserves as of December 31, 2014. Prices were calculated using the
unweighted average of the first-day-of-the-month pricing for the twelve months ended December 31, 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. A copy of Netherland Sewell’s summary report is included as
Exhibit 99.2 to this Annual Report on Form 10-K.
Estimated Proved Reserves as of December 31, 2014(1)
Crude Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total Proved
Reserves
(MBoe)(2)
Standardized
Measure of
Discounted Cash
Flows(3)
Proved Developed Producing . . . . . . . . . . . . . . . .
Proved Developed Non-Producing . . . . . . . . . . . .
Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . .
8,918
12
1,053
1,093
5
131
13,069
92
1,209
12,189
32
1,386
(in thousands)
$286,179
655
18,363
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,983
1,229
14,370
13,607(4)
$305,197
(1)
Includes reserves attributable to our 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) Standardized measure of discounted cash flows represents the present value of estimated future net revenue
to be generated from the production of proved reserves, determined in accordance with the rules and
19
regulations of the SEC (using prices and costs in effect as of the date of estimation), less future
development, production and income tax expenses, and discounted at 10% per annum to reflect the timing
of future net revenue.
(4)
Includes 12,144 MBoe of estimated proved reserves attributable to our non-operated working interests in oil
and natural gas properties in the Williston Basin, approximately 10% of which were proved undeveloped
reserves.
Proved Undeveloped Reserves
As of December 31, 2014, our estimated proved undeveloped reserves were 1,386 MBoe. During 2014, we
participated in 33 wells related to the conversion of estimated proved undeveloped reserves with associated
capital expenditures of $5.2 million. During 2014, we converted 704 MBoe of estimated proved undeveloped
reserves to estimated proved developed reserves. As of December 31, 2014, we had no estimated proved
undeveloped reserves that have remained undeveloped for more than five years, and we expect all estimated
proved undeveloped reserves reported herein will be developed within the next two years.
For additional information on our estimated proved reserves, see Note 19 to the audited consolidated
financial statements included elsewhere in this Annual Report on Form 10-K.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Netherland Sewell, our independent reserve engineering firm, estimated, in accordance with generally
accepted petroleum engineering and evaluation principles and definitions and guidelines established by the
Securities and Exchange Commission, 100% of our proved reserves as of December 31, 2014. The Netherland
Sewell technical personnel responsible for preparing the reserve estimates presented herein meet the
requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers. See Exhibit 99.2 included as an exhibit to this Annual Report on Form 10-K for further
discussion of the qualifications of Netherland Sewell personnel.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with
our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Netherland
Sewell in their reserves estimation process. In the fourth quarter, our technical team was in contact regularly with
representatives of Netherland Sewell to review properties and discuss methods and assumptions used in
Netherland Sewell’s preparation of the year-end reserves estimates. A copy of the Netherland Sewell reserve
report was reviewed by our internal technical staff prior to the inclusion of such report in this Annual Report on
Form 10-K.
Our Director-Engineering and Reserves is the technical person primarily responsible for overseeing the
preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering from the
University of Texas at Austin and is a member of the Society of Petroleum Engineers. Prior to joining NRP, he
spent nine years at DeGolyer and MacNaughton as a reservoir engineer working on multiple aspects of reserve
evaluation and appraisals. The Director-Engineering and Reserves reports directly to our Vice President, Oil and
Gas.
20
Production and Price History
The following table sets forth summary information concerning our production results, average sales prices
and production costs for the year ended December 31, 2014 in total and for each field containing 15 percent or
more of our total proved reserves as of December 31, 2014. Production and price information for the years ended
December 31, 2013 and 2012 is not included, as our oil and natural gas producing activities were not material to
our results of operations for those years.
Year Ended December 31, 2014
Royalty and
Overriding
Royalty
Interests(2)
Williston
Basin(1)
Net Production Volumes:
Crude oil (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average sales prices:
Crude oil ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGLs ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average costs ($/Boe):
Production expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ad valorem and severance taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . .
DD&A expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
578
53
408
$77.85
$33.64
$ 5.04
$13.08
$ 7.91
$ 4.86
$25.73
33
18
1,313
$82.91
$34.56
$ 4.17
—
—
—
$22.06
Total
611
71
1,721
$78.12
$33.87
$ 4.37
$13.08
$ 7.91
$ 4.86
$24.70
(1) Represents volume, price and cost information relating to our non-operated Williston Basin working interest
properties.
(2) Represents information relating to our royalty and overriding royalty interests in oil and gas properties.
These interests are recorded net of costs.
For additional information on our production, sales prices and costs, see Note 19 to the audited consolidated
financial statements included elsewhere in this Annual Report on Form 10-K.
Drilling and Development Activities
We do not operate any wells or conduct any drilling activities. The following table sets forth information
with respect to the number of net wells drilled and completed on our properties during the year ended
December 31, 2014. Well information for the years ended December 31, 2013 and 2012 is not included, as our
oil and natural gas producing activities were not material to our results of operations for those years. Productive
wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable
rate of return. Net wells represent the total of our fractional working interests or royalty interests, as applicable,
owned in gross wells.
Development
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
Year Ended December 31, 2014
Productive
Dry
Total
Gross
123
0
123
Net
4.4
0
4.4
Gross
Net
Gross
0
0
0
0
0
0
123
0
123
Net
4.4
0
4.4
Producing Oil and Natural Gas Wells
The following table sets forth the gross and net producing oil and natural gas wells in which we held
working interests and royalty or overriding royalty interests as of December 31, 2014. Gross wells represent the
number of wells in which we own an interest. Net wells represent the total of our fractional working interests or
royalty interests, as applicable, owned in gross wells.
As of December 31, 2014
Working Interest Wells(1)
Royalty and Overriding Royalty Interest Wells(2)
Oil
Natural Gas
Oil
Natural Gas
Gross
Net
Gross
Net
Gross
Williston Basin . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . .
442
0
442
47
0
47
0
0
0
0
0
0
25
100
125
Net
0.1
5.2
5.3
Gross
0
987
987
Net
0
76
76
(1) As of December 31, 2014, we also owned non-operated working interests in 40 gross oil wells in various
stages of development in the Williston Basin.
(2) 57 gross (1.4 net) natural gas and oil wells are attributable to our overriding royalty interest in the Marcellus
Shale acquired in 2012. The remaining wells consist primarily of conventional oil and gas wells or coal bed
methane that are located in the southern portion of the Appalachian Basin.
Undeveloped Acreage Summary
The following table contains a summary of the undeveloped gross and net acres in which we had interests as
of December 31, 2014:
Williston Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Undeveloped Acres as of December 31, 2014
Acres Leased to NRP(1)
Net ORRI and Fee Mineral Acres
Gross
610
0
610
Net
384
0
384
ORRI(2)
Fee Mineral(3)
0
25,162
25,162
0
30,696
30,696
(1) Represents mineral acres leased by third parties to NRP.
(2) Represents net acres in which we have an overriding royalty interest in the Marcellus Shale acquired in
December 2012. Certain of the leases subject to the overriding royalty interest originally acquired have
expired but may be renewed. To the extent those leases are renewed, our overriding royalty interest in those
properties will continue.
(3) Represents net fee mineral acres owned by NRP and BRP LLC and leased to third parties.
Delivery Commitments
As of December 31, 2014, we had no material delivery commitments.
BRP LLC Joint Venture
BRP LLC is a joint venture between NRP and International Paper Company, in which we own a 51%
interest. As of December 31, 2014, BRP owned approximately 10 million mineral acres in 31 states. While the
vast majority of the 10 million acres remain largely undeveloped, BRP currently holds 71 mineral leases and 17
cell tower leases and has an active program to identify additional opportunities to lease its minerals to operating
parties. For the year ended December 31, 2014, BRP generated $8.0 million in revenue.
22
BRP’s assets include approximately 300,000 gross acres of oil and gas mineral rights in Louisiana, of which
over 54,000 acres were leased as of December 31, 2014. In addition to the leased mineral acreage, BRP holds a
1% overriding royalty interest on approximately 28,000 mineral acres in Louisiana. As of December 31, 2014,
BRP owned nearly 95,000 net mineral acres of coal rights (primarily lignite and some bituminous coal) in the
Gulf Coast region, of which approximately 5,800 acres are leased in Louisiana, Alabama and Texas. In addition,
BRP also owns copper rights in Michigan’s Upper Peninsula that are subject to a development agreement with a
copper development company. BRP also holds various other mineral rights including coalbed methane, metals,
aggregates, water and geothermal, in several states throughout the United States.
Significant Customers
In 2014, we had total revenues of $81.5 million from Foresight Energy LP and its affiliated companies and
$48.8 million from Alpha Natural Resources. Each of these lessees represented more than 10% of our total
revenues. The loss of one or both of these lessees could have a material adverse effect on us. In addition, the
closure or loss of revenue from Foresight’s Williamson mine, which accounted for 10% of our revenue in 2014,
could have a material adverse effect on us, but we do not believe that the loss of any other single mine on our
properties would have a material adverse effect on our revenues or distributable cash flow.
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.
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 OCI Wyoming does. Some of OCI 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 OCI Wyoming to retain its existing customers
and attract new customers, and could also intensify the negative impact of factors that decrease demand for soda
ash in the markets it serves, such as adverse economic conditions, weather, higher fuel costs and taxes or other
governmental or regulatory actions that directly or indirectly increase the cost or limit the use of soda ash.
The construction aggregates industry that VantaCore operates in is highly competitive and fragmented with
a large number of independent local producers in 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.
The oil and natural gas industry is intensely competitive, and we compete with other companies in that
industry who have greater resources than we do. These companies may be able to pay more for productive oil
and natural gas properties and may be able to expend greater resources to evaluate properties and attract and
maintain industry personnel. In addition, these companies may have a greater ability to make acquisitions in
times of low commodity prices. Our larger competitors may be able to absorb the burden of existing, and any
changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect
23
our competitive position. Our ability to acquire additional properties will be dependent upon our ability to
evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Title to Property
We owned approximately 99% of our coal and aggregates reserves in fee as of December 31, 2014. We
lease the remainder from unaffiliated third parties, including leasing aggregates reserves for VantaCore’s
construction materials business. OCI Wyoming also leases or licenses its trona reserves. As of December 31,
2014, we owned certain of our oil and gas reserves in fee and leased our non-operated working interests in the
Williston Basin from third parties. 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 operations 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 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.
However, to our knowledge none of the violations to date, nor the monetary penalties assessed, have been
material to our lessees or operations.
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 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. We do not accrue for such 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.
24
Many of the statutes discussed below also apply to exploration and development activities associated with
our interests in crude oil and natural gas properties and to the aggregates and industrial mineral mining
operations in which we hold interests, including VantaCore’s construction aggregates mining and production
operations and OCI 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 and
building 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.
The emission of air pollutants from the exploration and development of crude oil and natural gas is also
subject to the Clean Air Act and comparable state laws. In 2012, EPA published final New Source Performance
Standards for volatile organic compounds and sulfur dioxide and National Emissions Standards for Hazardous
Air Pollutants associated with oil and gas facilities. In January 2013, EPA granted petitions asking the agency to
reconsider and revise parts of this rule. Accordingly, in September 2013, EPA issued updates to the New Source
Performance Standards for the emission of volatile organic compounds from storage vessels used in crude oil and
natural gas production. Similarly, in December 2014, EPA finalized rules related to emissions from gas and
liquids during well completion. These rules could have an adverse effect on revenues from our interests in oil and
natural gas properties.
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 January 2014, EPA published proposed new source performance standards for greenhouse gas emissions
from new fossil fuel-fired electric generating units. The effect of the proposed rules would be to require partial
carbon capture and sequestration on any new coal-fired power plants, which may amount to their effective
prohibition. In June 2014, EPA proposed the Clean Power Plan, which outlined a multi-factor plan to cut carbon
emissions from existing electric generating units, including coal-fired power plants. Under this proposed rule,
existing power plants would be required to cut their carbon dioxide emissions 30% from 2005 levels by the year
2030. The effect of the proposed rules would be to require 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. EPA intends to
finalize these rules in the summer of 2015, both of which have been challenged by industry participants and other
parties. The implementation of these rules as proposed would have a material adverse effect on the demand for
coal by electric power generators.
25
President Obama also announced an emission reduction deal 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. While there is no way to estimate the impact of this
pledge, it could ultimately have an adverse effect on the demand for coal, both nationally and internationally.
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, as well as certain oil
and natural gas production facilities, on an annual basis.
On January 14, 2015, EPA announced plans to propose new regulations to reduce emissions of methane
from crude oil and natural gas production and transportation activities such as wells, pipelines, and valves levels
by up to 45 percent by 2025 (compared to 2012 levels). EPA expects to propose the new regulations in the
summer of 2015 and a final rule is expected in 2016.
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 OCI Wyoming soda ash businesses and in connection with our non-operated
working interests in oil and gas properties, to the extent of our proportionate interest therein.
Water Discharges
Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water
Act and analogous state laws and regulations create two permitting programs for mining operations. The National
Pollutant Discharge Elimination System (NPDES) program under Section 402 of the statute is administered by
the states or EPA and regulates the concentrations of pollutants in discharges of waste and storm water from a
mine site. The Section 404 program is administered by the Army Corps of Engineers and regulates the placement
of overburden and fill material into channels, streams and wetlands that comprise “waters of the United States.”
The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and may
include land features not commonly understood to be a stream or wetlands. The Clean Water Act and its
regulations prohibit the unpermitted discharge of pollutants into such waters, including those from a spill or leak.
Similarly, Section 404 also prohibits discharges of fill material and certain other activities in waters unless
authorized by the issued permit.
In 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 suit group lawsuits have been filed against mine
operators for allegedly violating conditions in their 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. Most of these cases were resolved prior to any appeal
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and it is difficult to predict whether such suits will continue to be successful. However, 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.
Drilling and development activities associated with our oil and natural gas business generate produced
water. Produced water is often disposed of in underground injection control (“UIC”) wells that receive permits
from EPA or from state agencies that have been granted authority to issue UIC issue permits by EPA. Failures or
delays in getting such permits could negatively impact exploration and production activities and, in turn,
adversely affect our oil and natural gas business.
Other Regulations Affecting the Mining Industry
Mine Health and Safety Laws
The operations of our lessees, VantaCore and OCI 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.
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Mining Permits and Approvals
Numerous governmental permits or approvals such as those required by SMCRA and the Clean Water Act
are required for mining operations. In connection with obtaining these permits and approvals, our lessees may be
required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any
proposed production of coal may have upon the environment. The requirements imposed by any of these
authorities may be costly and time consuming and may delay commencement or continuation of mining
operations.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including
our lessees, must submit a reclamation plan for reclaiming the mined property upon the completion of mining
operations. Our lessees have obtained or applied for permits to mine a majority of the reserves that are currently
planned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for
the additional reserves planned to be mined over the following five years. However, given the imposition of new
requirements in the permits in the form of policies and the increased oversight review that has been exercised by
EPA, there are no assurances that they will not experience difficulty and delays in obtaining mining permits in
the future. In addition, EPA has used its authority to create significant delays in the issuance of new permits and
the modification of existing permits, which has led to substantial delays and increased costs for coal operators.
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. OSM has stated that it is considering
future revisions to the buffer zone rule. Any revision or interpretation of the rule limiting or prohibiting valley
fills 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.
In April 2013, in Mingo Logan Coal Company v. EPA, the D.C. Circuit Court ruled that EPA has the
authority under the Clean Water Act to retroactively veto a Section 404 dredge and fill permit issued at a coal
mine by the U.S. Army Corps of Engineers. The decision creates uncertainties for all companies operating with
Clean Water Act fill permits and their business partners. While the specific facts of this case relate to ongoing fill
activities, the broadly written language of the decision could have sweeping implications in other areas and result
in increased regulatory activity by EPA that is adverse to the mining industry.
Other Regulations Affecting the Crude Oil and Natural Gas Industry
Hydraulic Fracturing
The exploration and production companies that operate the crude oil and natural gas properties in which we
have interests use hydraulic fracturing to recover oil and natural gas from tight rock formations. Hydraulic
fracturing is a process customary to the oil and gas industry in which water, sand and other additives are pumped
under high pressure into tight rock formations in a manner that creates or expands fractures in the rock to
facilitate oil and gas recovery. While hydraulic fracturing has been used to recover oil and natural gas for
decades, the practice has recently received increased scrutiny from various federal, state and local agencies, some
of which have prohibited the practice or called for further study of its effects. Future requirements that limit or
more strictly regulate the permitting or use of hydraulic fracturing could impact revenues from our oil and natural
gas properties.
Permitting
Additionally, state agencies are generally charged with issuing permits governing the location and
construction of drilling sites. Delays or failures to obtain such permits due to local land use or environmental
concerns could negatively impact revenues from our oil and gas operations.
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Transportation
Our revenues could be negatively impacted if the Federal Energy Regulatory Commission, which approves
interstate pipelines and certain gathering lines, fails to timely approve pipelines that transport oil or natural gas
produced from the properties in which we own interests. Additionally, our oil and natural gas revenues could be
negatively impacted by rules proposed in July 2014 by the United States Department of Transportation governing
the transportation of crude oil by rail. As proposed, the rules would require thousands of railroad tank cars to be
upgraded or phased out by 2017. Railroad tank car shortages resulting from the proposed rule could delay or
increase the costs of transportation of crude oil from our Williston Basin non-operated working interests and
negatively impact revenues from those properties.
Employees and Labor Relations
We historically have not had any employees. To carry out our operations, affiliates of our general partner
employ 89 people who directly support our operations. None of these employees are subject to a collective
bargaining agreement. As a result of our acquisition of VantaCore in the fourth quarter of 2014, we now employ
269 people who support VantaCore’s construction aggregates mining and production operations. None of these
employees are subject to a collective bargaining agreement.
Segment Information
We conduct all of our operations in a single segment – the ownership and leasing of natural resources and
related transportation and processing infrastructure. Substantially all of our owned properties are subject to
leases, and revenues are earned based on the volume and price of minerals extracted, processed or
transported. Included in revenues and other income from these natural resource properties are royalties from coal,
aggregates, oil and gas, timber, related transportation and processing infrastructure revenues, as well as other
income from our equity investment in OCI Wyoming’s trona mine and soda ash refinery operations, and
revenues from the VantaCore aggregates mining and production operation purchased during 2014.
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 charters for our Audit Committee, Conflicts Committee and Compensation,
Nominating and Governance Committee. Also, 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.
Item 1A. Risk Factors
Risks Related to Our Business
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of
financial reserves.
Because distributions on the common units are dependent on the amount of cash we generate, distributions
may 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, 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,
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cash distributions might be made during periods when we record losses and might not be made during periods
when we record profits. To the extent our board of directors deems appropriate, it may determine to decrease the
amount of the quarterly distribution.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations
and business prospects.
As of December 31, 2014, we and our subsidiaries had approximately $1.5 billion of total indebtedness. The
terms and conditions governing our indebtedness, including NRP’s 9.125% senior notes, Opco’s revolving credit
facility, term loan and senior notes, and NRP Oil and Gas’s revolving credit facility:
• 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;
• 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. If we do
not have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money,
sell assets or raise equity, and our ability to pursue acquisitions may be limited. 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. In addition, Opco’s revolving credit facility and term loan both
mature in 2016. We will be required to repay or refinance the amounts outstanding under these credit facilities
prior to their maturity. We may not be able to refinance these amounts on terms acceptable to us, if at all, or the
borrowing capacity under Opco’s revolving credit facility may be substantially reduced.
The borrowing base under NRP Oil and Gas’s revolving credit facility is based on the value of our proved
reserves and is redetermined on a semi-annual basis in May and October of each year. The current oil price
environment or future declines in prices or reduced production from or development of our properties could
result in a determination to lower the borrowing base. In such event, we may not be able to access funding under
the facility necessary to operate our business or we could be required to repay any indebtedness in excess of the
redetermined borrowing base.
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 access the capital markets may be challenging in the
current commodity price environment. Our ability to comply with the financial and other restrictive covenants in
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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.
Coal prices continue to be severely depressed, which has 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 and remain at levels
close to or below the level of operating costs for a number of our lessees. The prices our lessees receive for their
coal depend upon factors beyond their or our control, including:
• the supply of and demand for domestic and foreign coal;
• domestic and foreign governmental regulations and taxes;
• changes in fuel consumption patterns of electric power generators;
• the price and availability of alternative fuels, especially natural gas;
• global economic conditions, including the strength of the U.S. dollar relative to other currencies and the
demand for steel;
• 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 are also at multi-year lows due to global economic conditions. 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.
Lower prices have reduced the quantity of coal that may be economically produced from our properties,
which has in turn reduced 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. For the year ended December 31, 2014, we took an impairment
charge of $17.6 million relating to certain of our coal related properties. With the continued weakness in the coal
markets, we intend to closely monitor our coal assets impairment risk. Future impairment analyses could result in
downward adjustments to the carrying value of our assets.
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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 could 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 January 2014, EPA published proposed new source performance standards for GHG emissions from new
fossil fuel-fired electric generating units. The effect of the proposed rules would be to require partial carbon
capture and sequestration on any new coal-fired power plants, which may amount to their effective prohibition.
In June 2014, EPA proposed the Clean Power Plan, which outlined a multi-factor plan to cut carbon emissions
from existing electric generating units, including coal-fired power plants. Under this proposed rule, existing
power plants would be required to cut their carbon dioxide emissions 30% from 2005 levels by the year 2030.
The effect of the proposed rules would be to require 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. EPA intends to finalize
these rules in the summer of 2015, both of which have been challenged by industry participants and other parties.
The implementation of these rules as proposed would have a material adverse effect on the demand for coal by
electric power generators and as a result on our coal related-revenues.
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 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.
The emission of air pollutants from the exploration and development of crude oil and natural gas and related
facilities is also subject to the Clean Air Act and comparable state laws. In 2012, EPA published final New
Source Performance Standards for volatile organic compounds and sulfur dioxide and National Emissions
Standards for Hazardous Air Pollutants associated with oil and gas facilities. In January 2013, EPA granted
petitions asking the agency to reconsider and revise parts of this rule. Accordingly, in September 2013, EPA
issued updates to the New Source Performance Standards for the emission of volatile organic compounds from
storage vessels used in crude oil and natural gas production. Similarly, in December 2014, EPA finalized rules
related to emissions from gas and liquids during well completion. These rules could have an adverse effect on
revenues from our interests in oil and natural gas properties.
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In January 2015, EPA announced plans to propose new regulations to reduce emissions of methane from
crude oil and natural gas production and transportation activities such as wells, pipelines, and valves levels by up
to 45 percent by 2025 (compared to 2012 levels). EPA expects to propose the new regulations in the summer of
2015 and a final rule is expected in 2016. Any such rules could have a material adverse effect on our oil and
natural gas revenues.
Mining operations are subject to operating risks that could result in lower revenues to us. In addition, we
are subject to operating risks as a result of the VantaCore acquisition that we have not previously
experienced.
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;
• 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.
As a result of recent judicial decisions and the increased involvement of the Obama Administration and
EPA in the permitting process, 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.
Prior to the VantaCore acquisition, we did not operate aggregates mining and production assets. VantaCore
currently operates three hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal. As
an operator of these assets, we will be 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 and prevent us from realizing all of the anticipated benefits of the acquisition.
Prices for crude oil and natural gas are extremely volatile. An extended decline or further declines in crude
oil and natural gas prices could have an adverse effect on our results of operations
Crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in
supply and demand and on numerous other factors beyond our control, including:
• domestic and foreign supply of oil and natural gas;
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• the level of prices and expectations about future prices of oil and natural gas;
• the level of global oil and natural gas exploration and production;
• the cost of exploring for, developing, producing and delivering oil and natural gas;
• the price and quantity of foreign imports;
• political and economic conditions in oil producing countries, including the Middle East, Africa, South
America and Russia;
• the actions of the Organization of Petroleum Exporting Countries with respect to oil price and production
controls;
• speculative trading in crude oil and natural gas derivative contracts;
• the level of consumer product demand;
• weather conditions and other natural disasters;
• risks associated with drilling and completion operations;
• technological advances affecting energy consumption;
• domestic and foreign governmental regulations and taxes;
• the continued threat of terrorism and the impact of military and other action, including U.S. military
operations in the Middle East;
• the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation
facilities and the resulting differentials to market index prices;
• the price and availability of alternative fuels; and
• overall domestic and global economic conditions, including the relative value of the U.S. dollar to other
currencies.
Due to global oversupply of crude oil in part due to increasing U.S. production and a strong U.S. dollar,
crude oil prices have fallen significantly since the first half of 2014 to their lowest levels since 2008. In addition,
natural gas prices have also fallen to low levels due to record high levels of production and robust storage
inventories. These markets will likely continue to be volatile in the future, and any extended period of low prices
could have a material adverse effect on our results of operations from our oil and gas business.
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 OCI 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.
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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.
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, and oil and natural gas reserve engineering requires subjective
estimates of underground accumulations of coal, aggregates and industrial minerals, and oil and natural gas and
assumptions and are by nature imprecise. Our reserve estimates may vary substantially from the actual amounts
of coal, aggregates and industrial minerals, or oil and natural gas recovered from our reserves. There are
numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control.
Estimates of reserves necessarily depend upon a number of variables and assumptions, any one of which may, if
incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate
to:
• future prices, operating costs, capital expenditures, severance and excise taxes, and development and
reclamation costs;
• production levels;
• future technology improvements;
• the effects of regulation by governmental agencies; and
• geologic and mining conditions, which may not be fully identified by available exploration data.
Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates,
and these variations may be material. As a result, you should not place undue reliance on our reserve data that is
included in this report.
As a result of consolidation in the coal industry and our partnership with Foresight Energy, we derive a
large percentage of our revenues and other income from a small number of coal lessees.
In 2014, we derived 20% and 12% of our total revenues and other income from Foresight Energy LP and
Alpha Natural Resources, respectively. Foresight’s Williamson mine alone was responsible for approximately
10% of our total revenues and other income in 2014. As a result, we have significant concentration of revenues
with these lessees. If our lessees merge or otherwise consolidate, or if we acquire additional reserves from
existing lessees, then our revenues could become more dependent on fewer mining companies. If issues occur at
those companies that impact their ability to pay us royalties, our revenues and ability to make future distributions
would be adversely affected.
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 OCI Wyoming’s soda ash production
operations. If the market price for soda ash declines, OCI 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 OCI Wyoming receives for its soda ash depend on numerous factors
beyond OCI Wyoming’s control, including worldwide and regional economic and political conditions impacting
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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. Substantial or extended
declines in prices for soda ash could have a material adverse effect on our results of operations. In addition, OCI
Wyoming relies on natural gas as the main energy source in its soda ash production process. Accordingly, high
natural gas prices increase OCI 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, which is recovering at a slow pace.
The construction aggregates industry is highly fragmented with a large number of independent local
producers in 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.
We may incur unanticipated costs or delays in connection with the integration of VantaCore and future
aggregates operations into our company.
There are risks with respect to the integration of VantaCore into our company that may result in
unanticipated costs or delays to us. Such risks include:
• integrating additional personnel into our company, including the 269 people employed by VantaCore;
• establishing the internal controls and procedures for the acquired businesses that we are required to
maintain under the Sarbanes-Oxley Act of 2002;
• consolidating other corporate and administrative functions;
• diversion of management’s attention away from our other business concerns;
• loss of key employees; and
• the assumption of any undisclosed or other potential liabilities of the acquired company.
Similar risks may apply to the integration of future aggregates operations that we may acquire through the
VantaCore platform. Any significant costs and delays resulting from the risks described above could cause us not
to realize the anticipated benefits of these acquisitions.
We may be subject to risks in connection with oil and gas asset acquisitions.
The acquisition of oil and gas properties requires an assessment of several factors, including:
• recoverable reserves;
• the pace of development and drilling and completion activities by operators;
• future crude oil and natural gas prices and their differentials;
• the availability of and access to takeaway and transportation;
• future development costs, operating costs and property taxes;
• governmental regulations; and
• potential environmental and other liabilities.
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The accuracy of these assessments is inherently uncertain. In connection with these assessments, we
perform a review of the subject properties we believe to be generally consistent with industry practices. Our
review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with
the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always
be performed on every well, and environmental problems are not necessarily observable even when an inspection
is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable
to provide effective contractual protection against all or part of the problems. We often are not entitled to
contractual indemnification for environmental and other liabilities and acquire properties on an “as is” basis.
Our business will be adversely affected if we are unable to make acquisitions or access the bank and capital
markets to finance our growth.
Because our reserves decline due to production, our future success and growth depend, in part, upon our
ability to make acquisitions to replace reserves that are depleted. If we are unable to make acquisitions on
acceptable terms, our revenues will decline as our reserves are depleted. Our ability to acquire additional interests
in mineral reserves or make other acquisitions is dependent in part on our ability to access the bank and capital
markets. We cannot be certain that funding will be available if needed and to the extent required, on acceptable
terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to
complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures,
any of which could have a material adverse effect on our revenues, results of operations and quarterly
distributions. In addition, if we are unable to successfully integrate the companies, businesses or properties we
are able to acquire, our revenues may decline and we could experience a material adverse effect on our business,
financial condition or results of operations.
There is a possibility that any acquisition could be dilutive to our earnings and reduce our ability to make
distributions to unitholders. Any debt we incur to finance an acquisition may also reduce our ability to make
distributions to unitholders. Our ability to make acquisitions in the future also could be limited by restrictions
under our existing or future debt agreements, competition from other mineral companies for attractive properties
or the lack of suitable acquisition candidates.
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
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• 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 OCI Wyoming or our non-operated oil and gas working
interest properties. We have limited approval rights with respect to OCI Wyoming, and our partner controls most
business decisions, including decisions with respect to distributions and capital expenditures. Adverse
developments in OCI Wyoming’s business would result in decreased distributions to NRP. The oil and gas
properties in which we own working interests are operated by third-party operators and involve third-party
working interest owners. We have limited ability to influence or control the operation or future development of
such properties, including compliance with environmental, safety and other regulations, or the amount of capital
expenditures required to fund such properties. These limitations and our dependence on the operator and other
working interest owners for these projects could cause us to incur unexpected future costs and materially
adversely affect our financial condition and results of operations. 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.
Oil and gas development activities require substantial capital. We may be unable to obtain needed capital or
financing on satisfactory terms or at all, which could lead to a decline in the value of our properties and a
decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We have capital expenditures and operating expenses
associated with the wells in which we own working interests and are required to fund our proportionate share on
any wells in which we decide to participate. Our share of capital expenditures relating to our working interests
could exceed our revenues from those interests. Moreover, we are dependent on the other working interest
owners of such projects to fund their contractual share of the capital expenditures of such projects.
Our operations and other capital resources may not provide cash in sufficient amounts to maintain planned
or future levels of capital expenditures. Further, our actual capital expenditures could exceed our capital
expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of
capital we have available, we could be required to seek additional sources of capital, which may include
additional reserve based borrowings, debt financing, joint venture partnerships, production payment financings,
sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain debt or equity
financing on terms favorable to us, or at all. If we are unable to fund our capital requirements, we may be
required to decline to participate in wells, which in turn could lead to a decline in the value of our assets or a
decline in our oil and natural gas reserves.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the
production of coal, oil and gas, soda ash, and other minerals from our properties.
Transportation costs represent a significant portion of the total delivered cost for the customers of our
lessees. Increases in transportation costs could make coal a less competitive source of energy or could make
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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 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, OCI 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 OCI 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. OCI
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 OCI Wyoming’s facility, and alternative methods of
transportation are impracticable or cost-prohibitive. Any substantial interruption in or increased costs related to
the transportation of OCI Wyoming’s soda ash could have a material adverse effect on our financial condition
and results of operations.
The marketability of our crude oil and natural gas production depends in part on the availability, proximity
and capacity of pipeline and rail systems owned by third parties. The lack or unavailability of capacity on these
systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of,
development plans for properties in which we own oil and gas interests. In addition, as a result of pipeline
constraints in the Williston Basin, a significant amount of crude oil production from the region is transported by
rail. Train derailments in the U.S. and Canada have resulted in increased regulatory scrutiny of the transportation
of crude oil by rail. Any resulting regulations could result in increased transportation costs, which would
negatively affect our profitability from our Williston Basin assets.
We may incur losses and be subject to liability claims as a result of our ownership of working interests in oil
and natural gas operations. Additionally, our insurance may be inadequate to protect us against these risks.
As an owner of working interests in oil and natural gas operations, we are responsible for our proportionate
share of any losses and liabilities arising from uninsured and underinsured events, which could adversely affect
our business, financial condition or results of operations. We are subject to all of the risks associated with drilling
for and producing crude oil and natural gas, including the possibility of:
• environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic
fracturing fluids, and toxic gas or other pollutants into the environment, including groundwater and
shoreline contamination;
• abnormally pressured formations;
• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
• fires, explosions and ruptures of pipelines;
• personal injuries and death;
• natural disasters; and
• spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or
other pollutants by third party service providers.
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Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us
as a result of:
• injury or loss of life;
• damage to and destruction of property, natural resources and equipment;
• pollution and other environmental damage;
• regulatory investigations and penalties;
• suspension of our operations; and
• repair and remediation costs.
We may elect not to obtain insurance if we believe the cost of available insurance is excessive relative to the
risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence
of an event that is not fully covered by insurance could have a material adverse effect on our business, financial
condition and results of operations.
Our lessees could satisfy obligations to their customers with minerals from properties other than ours,
depriving us of the ability to receive amounts in excess of minimum royalty payments.
Mineral supply contracts generally do not require operators to satisfy their obligations to their customers
with resources mined from specific reserves. Several factors may influence a lessee’s decision to supply its
customers with minerals mined from properties we do not own or lease, including the royalty rates under the
lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and
customer specifications. In addition, lessees move on and off of our properties over the course of any given year
in accordance with their mine plans. If a lessee satisfies its obligations to its customers with minerals from
properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty
revenues.
A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process
or our mine inspection process or, if identified, might be identified in a subsequent period.
We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our
regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do
discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered
reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to
accounting disputes as well as disputes with our lessees.
Risks Related to Our Structure
Unitholders may not be able to remove our general partner even if they wish to do so.
Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation,
unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect
the general partner or the directors of the general partner on an annual or any other basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have
little practical ability to remove our general partner or otherwise change its management. Our general partner
may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding 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:
• 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
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• 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.
We may issue additional common 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 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:
• an existing unitholder’s proportionate ownership interest in NRP will decrease;
• the amount of cash available for distribution on each unit may decrease;
• the relative voting strength of each previously outstanding unit may be diminished; and the market price
of the common units may decline.
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:
• we do not have any employees and we rely solely on employees of affiliates of the general partner;
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• under our partnership agreement, we reimburse the general partner for the costs of managing and for
operating the partnership;
• the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay
quarterly distributions to unitholders;
• the general partner tries to avoid being liable for partnership obligations. The general partner is permitted
to protect its assets in this manner by our partnership agreement. Under our partnership agreement the
general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if
we can obtain more favorable terms without limiting the general partner’s liability;
• under our partnership agreement, the general partner may pay its affiliates for any services rendered on
terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its
affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates)
are not necessarily the result of arm’s-length negotiations; and
• the general partner would not breach our partnership agreement by exercising its call rights to purchase
limited partnership interests or by assigning its call rights to one of its affiliates or to us.
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 revolving credit agreement.
During the continuance of an event of default under our revolving credit agreement, 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. 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 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, which is currently a maximum of 35% 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
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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.
The tax treatment of publicly traded partnerships or an investment in our common 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. For example, from time to time, members of Congress propose and consider
substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such
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. We are unable to predict whether any of these changes or other proposals will be reintroduced or will
ultimately be enacted. Any such changes could negatively impact the value of an investment in our common
units. Any modification to 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 a
partnership for U.S. federal income tax purposes.
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.
You are required to pay taxes on your share of our income even if you do not receive any cash distributions
from us.
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.
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
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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.
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,
instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be
permitted under existing Treasury Regulations. The U.S. Treasury Department’s proposed Treasury Regulations
allowing a similar monthly simplifying convention are not final and do not specifically authorize the use of the
proration method we have adopted. If the IRS were to successfully challenge our proration method or new
Treasury Regulations were issued, 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.
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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. Our termination 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 our taxable income. 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 recently 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.
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.
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.
45
Item 2. Properties.
The information required by this Item is included under “Item 1. Business” in this Annual Report on Form
10-K and is incorporated by reference herein.
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.
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.
46
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 23, 2015,
there were approximately 43,400 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, 2013 to December 31, 2014, and the quarterly cash distribution
declared and paid with respect to each quarter per common unit.
Price Range
Cash Distribution History
High
Low
Per
Unit
Record
Date
Payment
Date
2013
First Quarter . . . . . . . . . . . . . . . . . . . . . .
Second Quarter
. . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . .
2014
First Quarter . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
Second Quarter
Third Quarter . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . .
$23.95
$24.37
$22.39
$21.57
$20.72
$16.57
$16.91
$13.83
$18.93
$20.08
$18.98
$18.99
$14.80
$12.78
$12.56
$ 7.97
$0.5500
$0.5500
$0.5500
$0.3500
$0.3500
$0.3500
$0.3500
$0.3500
05/06/2013
08/05/2013
11/05/2013
01/21/2014
05/14/2013
08/14/2013
11/14/2013
01/31/2014
05/05/2014
08/05/2014
11/05/2014
02/05/2015
05/14/2014
08/14/2014
11/14/2014
02/13/2015
Cash Distributions to Partners
General
Partner(1)
Limited
Partners(2)
Total
Distributions
2013 Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,930
$3,241
(1) Represents distributions on our general partner’s 2% general partner interest in us.
(2)
Includes distributions on 1,560,000 common units held by our general partner.
(in thousands)
$241,588
$158,801
$246,518
$162,042
Unregistered Sales of Equity Securities
As previously reported, in connection with the closing of the VantaCore acquisition, on October 1, 2014, we
issued 2,426,690 common units to certain of the owners of VantaCore in exchange for their interests in
VantaCore and VantaCore GP upon closing of the acquisition. The aggregate offering price of the common units
as of the date of issuance was approximately $31.6 million. On December 4, 2014, we issued an additional 813
units to certain of the former owners of VantaCore in connection with a post-closing adjustment to the purchase
price for the acquisition. The aggregate offering price of such additional common units as of the date of issuance
was approximately $8,500. Such common units were issued and sold in reliance upon an exemption from the
registration requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.
47
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.”
Natural Resource Partners L.P. Selected Financial Data
For the Years Ended December 31,
2014
2013
2012
2011
2010
Total revenues and other income . . . . . . . . . $ 399,752 $ 358,117
$
Asset impairments . . . . . . . . . . . . . . . . . . . . .
734
$ 188,919 $ 236,236
Income from operations . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 108,830 $ 172,078
Basic and diluted net income per limited
26,209 $
(in thousands, except per unit data)
$ 379,147
$
2,568
$ 267,165
$ 213,355
$ 377,683
$ 161,336
$ 104,135
54,026
$
$ 301,401
$
—
$ 196,061
$ 154,461
partner unit
. . . . . . . . . . . . . . . . . . . . . . . .
Distributions paid ($ per unit) . . . . . . . . . . . .
Weighted average number of common units
outstanding . . . . . . . . . . . . . . . . . . . . . . . .
Cash from operations . . . . . . . . . . . . . . . . . .
Distributable cash flow(1) . . . . . . . . . . . . . . .
Adjusted EBITDA(1) . . . . . . . . . . . . . . . . . .
Balance sheet data:
Cash and cash equivalents . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt
. . . . . . . . . . . . . . . . . . . . . . .
Partners’ capital . . . . . . . . . . . . . . . . . . . . . . .
$
$
0.94
1.40
$
$
1.54
2.20
$
$
1.97
2.20
$
$
0.50
2.17
$
$
1.54
2.16
113,262
109,584
$ 210,755 $ 247,074
$ 217,710 $ 309,394
$ 300,322 $ 340,345
106,028
$ 271,408
$ 298,899
$ 328,116
106,028
$ 305,574
$ 311,174
$ 329,660
81,917
$ 258,694
$ 260,274
$ 253,074
92,513
50,076 $
$
95,506
$ 149,424
$2,444,724 $1,991,856 $1,764,672 $1,665,649 $1,664,036
$ 661,070
$1,394,240 $1,084,226 $ 897,039
$ 825,180
$ 617,447
$ 720,155 $ 616,789
$ 836,268
$ 644,915
$ 214,922
$
(1) See “—Non-GAAP Financial Measures” below.
Non-GAAP Financial Measures
Distributable Cash Flow
Under our partnership agreement, we are required to distribute all of our available cash each quarter.
Because distributable cash flow is a significant liquidity metric that is an indicator of our ability to generate cash
flows in order to make quarterly cash distributions to our partners, we view it as the most important measure of
our success as a company. Distributable cash flow is also the quantitative standard used in the investment
community with respect to publicly traded partnerships.
Our distributable cash flow represents cash flow from operations, plus returns on unconsolidated equity
investments, proceeds from sales of assets, and returns on direct financing lease and contractual overrides.
Although distributable cash flow is a “non-GAAP” financial measure, we believe it is a useful adjunct to net cash
provided by operating activities under GAAP. Distributable cash flow 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. Distributable cash flow may not be calculated the same for us as for other companies.
48
Reconciliation of “Net cash provided by operating activities” to “Distributable cash flow”
Year Ended December 31,
2014
2013
2012
2011
2010
Net cash provided by operating activities . . . . . . . . . .
Returns on unconsolidated equity investments . . . . . .
Returns on direct financing lease and contractual
overrides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sales of assets . . . . . . . . . . . . . . . . . . . .
(in thousands)
$210,755 $247,074 $271,408 $305,574 $258,694
—
48,833
3,633
—
—
1,904
1,418
2,558
10,929
2,669
24,822
—
5,600
—
1,580
Distributable cash flow . . . . . . . . . . . . . . . . . . . . . . . . .
$217,710 $309,394 $298,899 $311,174 $260,274
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income less equity and other
unconsolidated investment income; plus distributions from unconsolidated affiliates, interest expense, gross,
depreciation, depletion and amortization, and asset impairments. Adjusted EBITDA, 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. Adjusted EBITDA should not be considered in insolation or
as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financial
activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDA
provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures,
and working capital movement or tax positions. Adjusted EBITDA does not represent funds available for
discretionary use because those funds may be required for debt service, capital expenditures, working capital and
other commitments and obligations. Our management team believes Adjusted EBITDA is useful in evaluating
our financial performance because this measure is widely used by financial analysts, investors and rating
agencies for comparative purposes. NRP entered the high-yield bond market in 2013, and Adjusted EBITDA is a
financial measure widely used by investors in that market. 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 or loss, the lack of comparability of results of operations of different companies
and the different methods of calculating Adjusted EBITDA reported by different companies.
Reconciliation of “Net income” to “Adjusted EBITDA”
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less equity and other unconsolidated investment
income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add distributions from unconsolidated affiliates . . . . .
Add depreciation, depletion and amortization . . . . . . .
Add asset impairments . . . . . . . . . . . . . . . . . . . . . . . . .
Add interest expense, gross . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2014
2013
2012
2011
2010
(in thousands)
$108,830 $172,078 $213,355 $ 54,026
$154,461
(41,416)
46,638
79,876
26,209
80,185
(34,186)
72,946
64,377
734
64,396
—
—
58,221
2,568
53,972
—
—
65,118
161,336
49,180
—
—
56,978
—
41,635
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$300,322 $340,345 $328,116 $329,660 $253,074
Adjusted EBITDA presented in the table above differs from the EBITDDA definitions contained in Opco’s
debt agreement covenants. In calculating EBITDDA for purposes of Opco’s debt covenant compliance, pro
forma effect may be given to acquisitions and dispositions made during the relevant period. See “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources—Contractual Obligations and Commercial Commitments—Opco Debt” for a description of Opco’s
debt agreements.
49
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion of the financial condition and results of operations should be read in conjunction
with the historical financial statements and notes thereto included elsewhere in this filing and the financial
statements and footnotes included elsewhere in this Annual Report on Form 10-K for the year ended
December 31, 2014.
As used in this Item 7, unless the context otherwise requires: “we,” “our” and “us” 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 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.
Executive Overview
We engage 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, crude oil and natural gas,
construction aggregates, frac sand and other natural resources. Executing on our plans to diversify our business,
we have completed over $900 million in acquisitions since January 2013. For the year ended December 31, 2014,
we recorded revenues and other income of $399.8 million and Adjusted EBITDA of $300.3 million.
Approximately $226.7 million (57%) of our 2014 revenues and other income were attributable to coal-related
sources, and $173.0 million (43%) of our revenues and other income were attributed to non-coal-related sources.
Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income,
see “Item 6. Selected Financial Data—Non-GAAP Financial Measures—Adjusted EBITDA.”
Our coal reserves are located in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin
and the Western United States, as well as lignite reserves in the Gulf Coast region. We do not operate any coal
mines, but lease our coal 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. We also own and manage infrastructure
assets that generate additional revenues, primarily in the Illinois Basin.
We own or lease aggregates and industrial minerals located in a number of states across the country. We
derive a small percentage of our aggregates and industrial minerals revenues by leasing our owned reserves to
third party operators who mine and sell the reserves in exchange for royalty payments. However, the majority of
our aggregates and industrial minerals revenues come through our ownership of VantaCore Partners LLC, which
we acquired in October 2014. VantaCore specializes in the construction materials industry and operates three
hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal. VantaCore’s current
operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
We own a 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the
Green River Basin, Wyoming. OCI 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.
We own various interests in oil and gas properties that are located in the Williston Basin, the Appalachian
Basin, Louisiana and Oklahoma. Our interests in the Appalachian Basin, Louisiana and Oklahoma are minerals
and royalty interests, while in the Williston Basin we own non-operated working interests. Our Williston Basin
non-operated working interest properties include the properties acquired in the Sanish Field from an affiliate of
Kaiser-Francis Oil Company in November 2014.
Current Liquidity Position
As of December 31, 2014, we had $100 million in available borrowing capacity under Opco’s revolving
credit facility, $27 million available under the NRP Oil and Gas revolving credit facility and $50.1 million in
cash.
50
We have $80.9 million in principal payments due on NRP Operating’s senior notes each year through 2018,
and NRP Operating’s revolving credit facility and term loan facility both mature in 2016. While we believe we
have sufficient liquidity to meet our current financial needs, we will be required to repay or refinance the
amounts outstanding under Opco’s credit facilities prior to their maturity. While we believe we will be able to
refinance these amounts, we may not be able to do so on terms acceptable to us, if at all, or the borrowing
capacity under Opco’s revolving credit facility may be substantially reduced. Our ability to refinance these
amounts may depend in part on our ability to access the debt or equity capital markets, which will be challenging
in the current commodity price environment. See “—Liquidity and Capital Resources” for a further description
of our indebtedness, cash flows and capital expenditures.
Current Results/Market Outlook
Our revenues and other income from sources other than coal represented 43% of our total revenues and
other income in 2014, as compared to 23% of total revenues and other income in 2013. Although our total
revenues and other income for 2014 increased over 2013, our coal-related revenues were down 17% compared to
the same period. The majority of the decrease in coal-related revenues was due to lower Appalachian coal royalty
revenues, which were down approximately 19% from 2013. During 2014, our investment in OCI Wyoming’s
trona mining and soda ash production operations contributed $41.4 million in other income, up $7.2 million from
2013, and our oil and gas revenues increased to $59.6 million, triple our oil and gas revenues in 2013.
The coal markets remained challenged during the year and do not currently show signs of recovery.
Although thermal coal prices continue to be depressed, we believe that thermal coal production from our
properties in the low-cost Illinois Basin will continue to remain strong in spite of the weak thermal markets. We
expect the markets for thermal coal from our other regions to remain weak during 2015. We continue to have
substantial exposure to metallurgical coal, from which we derived approximately 40% of our coal royalty
revenues and 32% of the related production during 2014. The first quarter 2015 benchmark price for
metallurgical coal remains at a multi-year low, and the global metallurgical coal market continues to suffer from
oversupply in addition to reduced demand from China and a relatively strong U.S. dollar. We do not anticipate
that metallurgical coal prices will recover in 2015. While we have not been significantly impacted so far by the
various metallurgical coal mine idlings announced during the second half of 2014, additional mine idlings
resulting in reductions of production of metallurgical coal from our properties may occur in 2015 if prices remain
at current levels. In addition, if coal prices continue to remain depressed for an extended period of time, the
lessees on some of our coal properties may close some of their mines causing some of our coal properties to be
impaired.
Our trona mining and soda ash refinery investment performed in line with our expectations during 2014.
The international market for soda ash continues to grow, as global production capacity for high-cost synthetic
soda ash continues to be reduced, and OCI Wyoming’s sales through ANSAC were better than expected.
Domestic sales volumes, which are typically sold at higher prices than soda ash sold internationally, have
remained relatively stable. The cash we receive from OCI Wyoming is in part determined by the quarterly
distribution declared by OCI Resources LP. In February 2015, OCI Resources LP paid a quarterly distribution of
$0.5315 per common unit with respect to the fourth quarter of 2014, representing a slight increase over the
distribution paid with respect to the third quarter of 2014. OCI Resources LP also announced its intention to
increase its distributions with respect to 2015 by 3% to 6%.
VantaCore’s construction aggregates mining and production business is largely dependent on the strength of
the local markets that it serves. Its operations based in Clarksville, Tennessee and Baton Rouge, Louisiana will
depend on the pace of commercial and residential construction in those areas, each of which has been slowly
recovering from the 2008-2009 recession. VantaCore’s Laurel Aggregates operation in southwestern
Pennsylvania serves many of the producers and oilfield service companies operating in the Marcellus and Utica
Shales. To the extent that the pace of exploration and development of natural gas in those areas slows due to low
natural gas prices, we expect that VantaCore’s business will be affected. In addition, VantaCore’s business is
seasonal, with lower production and sales expected during the first quarter of each year due to winter weather.
51
Global oil prices have declined significantly since the second quarter of 2014 due to increased oil supply
driven by robust onshore U.S. development activity, coupled with reduced global demand and a strong U.S.
dollar. Natural gas prices are also low due to record levels of production and high storage inventories. As of the
date of this filing, we have not hedged any of our future oil or natural gas production and, as a result, our oil and
gas revenues will continue to be impacted by the current price environment. However, we are able to manage the
capital expenditures associated with our Williston Basin non-operated working interest properties by evaluating
well proposals on a well-by-well basis. We will continue to monitor the development programs of the operators
of these properties and manage the capital expenditures associated with those properties by only participating in
wells that are expected to provide acceptable economic returns.
Political, Legal and Regulatory Environment Affecting Our Coal Business
The political, legal and regulatory environment continues to be difficult for the coal industry. The
Environmental Protection Agency (“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. In addition, the electric utility industry, which is the most significant end-user of domestic coal, is
subject to extensive regulation regarding the environmental impact of its power generation activities. In January
2014, EPA published proposed new source performance standards for GHG emissions from new fossil fuel-fired
electric generating units. The effect of the proposed rules would be to require partial carbon capture and
sequestration on any new coal-fired power plants, which may amount to their effective prohibition. In June 2014,
EPA proposed the Clean Power Plan, which outlined a multi-factor plan to cut carbon emissions from existing
electric generating units, including coal-fired power plants. Under this proposed rule, existing power plants
would be required to cut their carbon dioxide emissions 30% from 2005 levels by the year 2030. The effect of the
proposed rules would be to require 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. EPA intends to finalize these rules in the
summer of 2015, both of which have been challenged by industry participants and other parties. The
implementation of these rules as proposed would have a material adverse effect on the demand for coal by
electric power generators and as a result on our coal related-revenues.
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),
which regulates emissions of nitrogen oxide and sulfur dioxide, and the Mercury and Air Toxics Rule (MATS),
which regulates emissions of hazardous air pollutants. Installation of additional emissions control technologies
and other measures required under these and other EPA regulations have made it more costly to operate many
coal-fired power plants and have resulted in and are expected to continue to result in plant closures. Further
reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed rules
and regulations would have a material adverse effect on our coal-related revenues.
Significant Acquisitions
Sanish Field. On November 12, 2014, we completed the purchase of a 40% member interest in Kaiser-
Whiting, LLC (“Kaiser LLC”) for $339 million, subject to customary post-closing purchase price adjustments.
Effective November 13, 2014, NRP Oil and Gas withdrew as a member of Kaiser LLC and an undivided 40%
interest in Kaiser LLC’s assets was distributed out of Kaiser LLC and assigned directly to NRP Oil and Gas. The
assets distributed to us included non-operated working interests in approximately 6,086 net acres with an average
working interest of approximately 14.5%. The assets, located in the Sanish Field in Mountrail County, North
Dakota, are all held by production and include 196 producing oil and gas wells as of December 31, 2014. See
“Note 3. Significant Acquisitions” to the audited consolidated financial statements included elsewhere in this
Annual Report on Form 10-K.
VantaCore Partners. On October 1, 2014, we completed the acquisition of VantaCore, a privately held
company specializing in the construction materials industry, for $201 million in cash and common units, subject
to customary post-closing purchase price adjustments. Headquartered in Philadelphia, Pennsylvania, VantaCore
operates three hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal.
52
VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
See “Note 3. Significant Acquisitions” to the audited consolidated financial statements included elsewhere in this
Annual Report on Form 10-K.
Sundance.
In December 2013, we acquired non-operated working interests in oil and gas properties in the
Williston Basin of North Dakota, including properties producing from the Bakken/Three Forks play, from
Sundance Energy, Inc. for $29.4 million, following post-closing purchase price adjustments. The properties,
which are all held by production are located in McKenzie, Mountrail and Dunn counties and are actively being
developed.
Abraxas.
In August 2013, we acquired non-operated working interests in producing oil and gas properties
in the Williston Basin of North Dakota and Montana, including properties producing from the Bakken/Three
Forks play, from Abraxas Petroleum Corporation for $38.0 million, following post-closing purchase price
adjustments.
OCI Wyoming.
In January 2013, we acquired a non-controlling equity interest in OCI Wyoming, an
operator of a trona ore mining operation and a soda ash refinery in the Green River Basin, Wyoming, from
Anadarko Holding Company and its subsidiary, Big Island Trona Company for $292.5 million. The acquisition
agreement provides for up to the net present value of $50 million in additional contingent consideration payable
by us should certain performance criteria be met as defined in the purchase and sales agreement in any of 2013,
2014 or 2015. As of December 31, 2014 we had accrued $14.5 million for contingent consideration payments, of
which we expect to pay $3.8 million to Anadarko with respect to 2014.
Critical Accounting Policies
Preparation of the accompanying financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the reported
amounts of assets 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 included elsewhere in this Annual Report on Form 10-K. The following critical accounting policies
are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements.
Equity Investments
We account for non-marketable 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 OCI 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 fair value of the underlying net assets of equity method
investees 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 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.” These earnings are
generated from natural resources, which are considered part of our core business activities consistent with its
53
directly owned revenue generating activities. 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 book
value, 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.
Revenues
Coal Related Revenues. Coal related revenues consist primarily of royalties as well as transportation and
processing fees. Royalty 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. 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.
Oil and Gas Revenues. Oil and gas related revenues consist of revenues from our non-operated working
interests, royalties and overriding royalties. Revenues related to our non-operated working interests in oil and gas
assets are recognized on the basis of our net revenue interests in hydrocarbons produced. We also have capital
expenditure and operating expenditure obligations associated with the non-operated working interests. Our
revenues fluctuate based on changes in the market prices for oil and natural gas, the decline in production from
producing wells, and other factors affecting the third-party oil and natural gas exploration and production
companies that operate our wells, including the cost of development and production. 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.
Aggregates and Industrial Minerals Related Revenues. Aggregates and industrial minerals related
revenues consist primarily of revenues generated in VantaCore’s construction aggregates business, royalties and
overriding royalties. 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. Aggregates
and industrial minerals royalty and overriding royalty 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.
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 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.
Deferred Revenue
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 deferred revenue when
received. The deferred revenue attributable to the minimum payment is recognized as revenue 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.
54
Lessee Audits and Inspections
We periodically audit lessee information by examining certain records and internal reports of our lessees.
Our regional managers also perform periodic mine inspections to verify that the information that has been
reported to us 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 us 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.
Share-Based Payment
We account for awards relating to our Long-Term Incentive Plan using the fair value method, which
requires us to estimate the fair value of the grant, and charge or credit the estimated fair value to expense over the
service or vesting period of the grant based on fluctuations in our 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.
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. 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. As a result of the continued weakness in the coal markets and the potential
for further declines in oil and natural gas prices, we intend to closely monitor our coal and oil and gas assets, and
the impairment evaluation process may be completed more frequently if deemed necessary. Future impairment
analyses could result in downward adjustments to the carrying value of our assets. During 2014, we recorded
impairment expense of $26.9 million on certain of our coal reserves, a preparation plant, intangible assets and
aggregates properties. For further discussion relating to our 2014 impairments see “Note 7. Plant and
Equipment,” “Note 8. Minerals Rights” and “Note 9. Intangible Assets” to the audited consolidated financial
statements included elsewhere in this Annual Report on Form 10-K
We evaluate our equity investments 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.
In accordance with FASB accounting and disclosure guidance for goodwill, we test our recorded goodwill
for impairment annually or more often if indicators of potential impairment exist, by determining if the carrying
value of a reporting unit exceeds its estimated fair value. Factors that could trigger an interim impairment test
include, but are not limited to, underperformance relative to historical or projected future operating results or
significant changes in our overall business, industry, or economic trends.
55
Business Combinations
For purchase acquisitions accounted for as a business combination, we are 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.
Recent Accounting Pronouncements
In May 2014, the FASB amended revenue recognition topics and created a new topic relating to revenue
recognition that will supersede existing guidance under U.S. GAAP. The core principle of the new guidance is to
recognize revenue when promised goods or services are transferred to the customer and in an amount that reflects
the consideration expected in exchange for those goods or services. To achieve this core principle, an entity
should (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract,
(3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the
contract and (5) recognize revenue when each performance obligation is satisfied. The guidance also specifies the
accounting for some costs to obtain or fulfill a contract with a customer. Disclosure requirements include
sufficient qualitative and quantitative information to enable financial statement users to understand the nature,
amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. The new topic
is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that
reporting period. The guidance allows for either full adoption or a modified retrospective adoption. We are
currently evaluating the requirements to determine the impact, if any, of this new topic on its financial position,
results of operations and cash flows.
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not
expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.
Results of Operations
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Adjusted EBITDA
Adjusted EBITDA declined 12% in 2014 to $300.3 million from $340.3 million generated in 2013. The
decrease is mainly related to the special distribution of $44.8 million received in 2013 from OCI Wyoming as
well as lower coal related revenues offset by higher earnings from our investments in aggregates and oil and gas.
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 and a reconciliation of this
measure to net income.
Distributable Cash Flow
Distributable cash flow for 2014 decreased by $91.7 million, or 30%, from 2013 to $217.7 million. This
change was due primarily to a $44.8 million special distribution received from OCI Wyoming in 2013, declines
in the coal business, and an additional $21.0 million of interest paid in 2014 that resulted in a $36.3 million
decrease in net cash provided by operations relative to 2013 and also a $9.5 million difference in proceeds from
the sale of assets. 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
and a reconciliation of this measure to net cash provided by operating activities.
56
Coal Related Revenues and Production
Regional Statistics
Coal royalty production (tons)
Appalachia:
For the Years Ended
December 31,
2014
2013
Increase
(Decrease)
Percentage
Change
(In thousands, except percent and per ton data)
(Unaudited)
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,339
20,092
3,914
33,345
13,177
2,844
1,093
50,459
11,505
20,801
4,151
36,457
13,087
2,778
970
53,292
(2,166)
(709)
(237)
(3,112)
90
66
123
(2,833)
Average coal royalty revenue per ton
Appalachia:
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Combined average gross royalty per ton . . . . . . . . . . . . . . . . . . . . . . .
Coal royalty revenues
Appalachia:
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
0.92
4.46
5.18
3.55
4.10
2.74
3.47
3.65
$
$
1.27
5.05
6.30
4.00
4.28
2.72
3.39
3.99
$
$
(0.35)
(0.59)
(1.12)
(0.44)
(0.18)
0.02
0.08
(0.34)
8,621
89,627
20,292
$ 14,643
105,004
26,156
$ (6,022)
(15,377)
(5,864)
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
118,540
54,049
7,804
3,793
145,803
56,001
7,569
3,290
(27,263)
(1,952)
235
503
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$184,186
$212,663
$(28,477)
Other coal related revenues
Override revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation and processing fees . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimums recognized as revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condemnation payment
Coal bonus payment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve swap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wheelage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
4,601
22,048
6,659
—
98
5,690
3,442
$ 10,372
22,519
6,528
10,370
—
8,149
3,593
$ (5,771)
(471)
131
(10,370)
98
(2,459)
(151)
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 42,538
$ 61,531
$(18,993)
Total coal related revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$226,724
$274,194
$(47,470)
(19)%
(3)%
(6)%
(9)%
1%
2%
13%
(5)%
(27)%
(12)%
(18)%
(11)%
(4)%
1%
2%
(9)%
(41)%
(15)%
(22)%
(19)%
(3)%
3%
15%
(13)%
(56)%
(2)%
2%
100%
100%
(30)%
(4)%
(31)%
(17)%
57
Total coal related revenues.
Total coal related revenues comprised approximately 57% and 77% of our
total revenues and other income for the years ended December 31, 2014 and 2013, respectively. The following is
a discussion of the major categories of coal related revenue:
Coal royalty revenues and production. Coal royalty revenues comprised approximately 46% and 59% of
our total revenues and other income for the years ended December 2014 and 2013, respectively. The following is
a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Coal royalty revenues decreased $27.3 million or 19% for the year ended December 31, 2014
compared to the same period of 2013, while production decreased 3.1 million tons or 9%.
Production from our properties in the Central Appalachian region decreased by 3%. This decrease was
primarily due to a greater proportion of mining on adjacent property and some lessees temporarily idling
production on our property. In addition, pricing realized by our lessees for both thermal and metallurgical coal in
Central Appalachia is generally below the levels received in the same period in 2013, causing a larger percentage
decrease in coal royalty revenues compared to the decrease in production.
The Southern Appalachian region also had decreased production and coal royalty revenues. This was due to
a new lessee being slower in building its production after succeeding a former lessee and one lessee temporarily
idling a mining unit on our property. In general our lessees received lower sales prices for both thermal and
metallurgical coal causing a larger percentage decrease in coal royalty revenue compared to the decrease in
production.
With respect to Northern Appalachia, for the year ended December 31, 2014 there was a decrease in coal
royalty revenues and production. These decreases were primarily due to the net effect of two longwall mines having
a greater proportion of their production on adjacent property in 2014 in the normal course of its mining plan.
Illinois Basin. Coal royalty revenues for the year ended December 31, 2014 decreased 3% when
compared to the same period in 2013, while production was nearly constant. The Williamson mine in Illinois had
lower production as did one of our properties in Indiana. These decreases were offset by higher production at the
Hillsboro mine and the Macoupin mine where an additional mining unit was added. We also received increased
revenue from a coal reserve acquisition completed in June 2014.
Northern Powder River Basin. Coal royalty revenues and production on our Western Energy property
were about the same for the year ended December 31, 2014 when compared to 2013.
Gulf Coast. Coal royalty revenues and production slightly increased for the year ended December 31, 2014
compared to the same period in 2013, due to one lessee having a greater proportion of mining on our property.
Other coal related revenues. Other coal related revenues for the year ended December 31, 2014 decreased
31% compared to the same period in 2013. The following is a discussion of the revenues derived from each of
the major sources of other coal-related revenue:
Override revenues for the year ended December 31, 2014 decreased by 56% compared to the same period in
2013 primarily due to one lessee moving its mining operations from an area on which we receive an overriding
royalty onto property on which we receive coal royalty revenues, another lessee exhausting the reserves subject
to the override and other lessees mining less on the area subject to our overriding royalty.
Transportation and processing fees decreased by $0.5 million or 2%, for the year ended December 31, 2014,
when compared to the same period in 2013. The decrease is primarily due to the temporary idling of two
processing facilities in response to market conditions which was partially offset by increased tonnage put through
our Macoupin facilities.
Minimums recognized as revenue were about the same for both years.
During the year ended December 31, 2014 we also recognized revenue of $5.7 million related to a reserve
swap completed in the third quarter. During 2013 we recognized $8.1 million on a similar swap. In addition,
2013 included a condemnation payment of $10.4 million.
58
Wheelage revenue decreased by 4% for the year ended December 31, 2014 compared to the same period in
2013. This increase was due to the normal fluctuations of tonnage that are subject to wheelage charges.
Aggregates and Industrial Minerals Revenues, and Other Related Income
For the Years Ended
December 31,
2014
2013
Increase
(Decrease)
Percentage
Change
(In thousands, except percent and per ton data)
(Unaudited)
VantaCore:
Tonnage sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total aggregates and industrial minerals related revenues . . . . . .
N/A
2,295
N/A
$42,051
$32,309
N/A
$12,073 $13,479
$54,124 $13,479
N/A
N/A
N/A
$ (1,406)
$ 40,645
N/A
N/A
N/A
(10)%
302%
Soda ash revenues and distributions:
Equity and other unconsolidated investment earnings . . . . . . . . . . . .
Cash distributions received from OCI Wyoming . . . . . . . . . . . . . . . .
$41,416 $34,186
$46,638 $72,946
$ 7,230
$(26,308)
21%
(36)%
Total aggregates and industrial minerals revenues, and other related income.
Total aggregates related
revenues, and other related income represented approximately 24% and 13% of our total revenues and other
income for both periods ended December 31, 2014 and 2013, respectively. The following is a discussion of the
major categories of these revenues:
VantaCore operating revenues contributed $42.1 million. We acquired VantaCore on October 1, 2014.
Aggregates and industrial minerals related revenues decreased 10% for 2014. This decrease is primarily due
to one of our lessees moving from property on which we receive royalty revenue to property on which we receive
overriding royalty revenue and another lessee temporarily idling its operation in early 2014. This decrease was
offset by an increase in override revenues of approximately $2.0 million in our overriding royalty revenues from
frac sand properties, the remaining increase is due to override revenues increasing on our Washington aggregates
property due to a lessee moving from our owned property to an area subject to an override.
Equity and other unconsolidated investment earnings.
Income from our investment in the OCI Wyoming
trona mining and soda ash production business was $41.4 million for the year ended December 31, 2014, and we
received $46.6 million in cash distributions during the year. For the same period in 2013, we recorded equity
income of $34.2 million and received $72.9 million in cash, which included a one-time special distribution of
$44.8 million. The increase in equity income of 21% over 2013 is due to improved earnings from OCI Wyoming
in 2014 over 2013.
59
Oil and Gas Revenues
For the Years Ended
December 31,
2014
2013
Increase
(Decrease)
Percentage
Change
(Dollars in thousands, except per unit data)
(Unaudited)
Williston Basin non-operated working interests:
Production volumes:
Oil (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGL (MBoe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
578
408
53
Average sales price per unit:
Oil (Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGL (Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 77.85
$
5.04
$ 33.64
Revenues:
Oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$44,995
2,056
1,783
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$48,834
Other oil and gas revenues:
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Royalty and overriding royalty revenues . . . . . . . . . . . . . . . . . . . . .
10,732
N/A
N/A
N/A
Total oil and gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$59,566 $17,080
$42,486
249%
Oil and gas revenues increased $42 million for the year ended December 31, 2014 when compared to the
year ended December 31, 2013. The increase in revenues is due to a full year of revenues from our non-operated
working interests in the Williston Basin that were acquired the second half of 2013. In addition, our 2014 results
include revenues attributable to our Sanish Field properties acquired on November 12, 2014.
Our average oil price received from our Williston Basin properties for the year ended December 31, 2014
was $77.85.
Due to the decline in oil prices in the fourth quarter of 2014, our average price for the fourth quarter
decreased to $63.17 which represents an 18.9% reduction as compared to full year.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Adjusted EBITDA
Adjusted EBITDA increased 4% to $340.3 million mainly due to our investment in OCI Wyoming that
generated $72.9 million that more than offset the significant declines of $69.2 million that we saw from our coal
related revenues. 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 and a
reconciliation of this measure to net income.
Distributable Cash Flow
Distributable cash flow increased by $10.5 million, or 4%, to $309.4 million mainly due to distributions of $72.9
million from OCI Wyoming in 2013, offset by lower cash flows from coal related assets and proceeds from the sale of
a preparation plant in 2012 of $4.7 million. 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 and a reconciliation of this measure to net cash provided by operating activities.
60
Coal Related Revenues and Production
Regional Statistics
Coal royalty production (tons)
Appalachia
For the Years Ended
December 31,
2013
2012
Increase
(Decrease)
Percentage
Change
(In thousands, except percent and per ton data)
(Unaudited)
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,505
20,801
4,151
36,457
13,087
2,778
970
53,292
10,486
26,098
3,718
40,302
11,299
2,377
466
54,444
1,019
(5,297)
433
(3,845)
1,788
401
504
(1,152)
Average coal royalty revenue per ton
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Combined average gross royalty per ton . . . . . . . . . . . . . . . . . . . . . . .
$
$
1.27
5.05
6.30
4.00
4.28
2.72
3.39
3.99
$
$
1.50
5.99
7.89
5.00
4.38
3.58
2.60
4.79
$
(.23)
(.94)
(1.59)
(1.00)
(.10)
(.86)
.79
(.80)
Coal royalty revenues
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 14,643
105,004
26,156
$ 15,768
156,390
29,325
$ (1,125)
(51,386)
(3,169)
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
145,803
56,001
7,569
3,290
201,483
49,538
8,501
1,212
(55,680)
6,463
(932)
2,078
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$212,663
$260,734
$(48,071)
Other coal related revenues
Override revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation and processing fees . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimums recognized as revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condemnation payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on Sale of Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve swap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wheelage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 10,372
22,519
6,528
10,370
—
8,149
3,593
$ 13,979
27,354
23,029
8,463
4,715
—
5,078
$ (3,607)
(4,835)
(16,501)
1,907
(4,715)
8,149
(1,485)
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 61,531
$ 82,618
$(21,087)
Total coal related revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$274,194
$343,352
$(69,158)
10%
(20)%
12%
(10)%
16%
17%
108%
(2)%
(15%)
(16%)
(20%)
(20)%
(2)%
(24)%
30%
(17)%
(7)%
(33)%
(11)%
(28)%
13%
(11)%
171%
(18)%
(26)%
(18)%
(72)%
23%
(100)%
100%
(29)%
(26)%
(20)%
61
Total coal related revenues.
Total coal related revenues comprised approximately 77% and 91% of our
total revenues and other income for the years ended December 31, 2013 and 2012, respectively. The following is
a discussion of the major categories of coal related revenue:
Coal royalty revenues and production. Coal royalty revenues comprised approximately 59% and 69% of
our total revenues and other income for the year ended December 31, 2013 and 2012, respectively. The following
is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Coal royalty revenues decreased $55.7 million or 28% for the year ended December 31, 2013
compared to the same period of 2012, while production decreased 3.8 million tons or 10%.
Production from our properties in the Central Appalachian region declined by 20% due to a combination of
the idling of mining units or mines, lower sales volumes from mines on our property and some mining units
moving off of our property to adjacent properties in the normal course of their mine plans. In addition, pricing
realized by our lessees for both thermal and metallurgical coal in Central Appalachia is generally below the
levels of the same period in 2012, causing a higher percentage decrease in coal royalty revenues compared to the
decrease in production.
The Southern Appalachian region also had increased production but decreased coal royalty revenues. The
increased production was due to one of our lessees having more normal production for 2013 after a slower start
in 2012 after making repairs to its preparation plant that was damaged by a tornado in 2011. In addition prices
from the metallurgical sales from our properties were lower than the same period in 2012, which contributed to
the decrease in coal royalty revenue.
With respect to Northern Appalachia, during the year ended December 31, 2013 there was also a decrease in
coal royalty revenue while we had an increase in production of 1.0 million tons or 10%. The increase in tonnage
was due to some lessees having a higher proportion of production on our properties. Those increases were
generally from leases with lower revenue per ton which caused the decrease in coal royalty revenue.
Illinois Basin. Coal royalty revenues for the year ended December 31, 2013 increased $6.5 million or
13% when compared to the same period in 2012, and production increased by 1.8 million tons, or 16%. The
increased production was primarily due to production from the Hillsboro mine which operated its longwall for
the entire year of 2013 after starting operation in 2012. This increase in production was partially offset by lower
production from the Williamson mine and lower production from the Macoupin mine which idled one of its
producing units in early 2013.
Northern Powder River Basin. Coal royalty revenues decreased on our Western Energy property despite
having higher production in 2013. The higher production was due to the normal variations in production that
occur on our checkerboard ownership. The lower coal royalty revenue was due to the timing of revenue
recognition by the lessee in the third quarter of 2012 that did not occur in 2013.
Gulf Coast. Coal royalty revenue and production for the year ended December 31, 2013 increased
compared to the same period in 2012 due to a mine having a greater proportion of production on our property in
2013.
Other coal related revenues. Other coal related revenues for the year ended December 31, 2013 decreased
26% compared to the same period in 2012. The following is a discussion of the revenues derived from each of
the major sources of other coal-related revenue:
Override revenue for the year ended December 31, 2013 decreased by 26% compared to the same period in
2012 due to one lessee moving its mining operations from an area on which we receive an overriding royalty
onto property on which we receive coal royalty revenue, one lessee exhausting the reserves subject to the
override and other lessees mining fewer tons on properties on which we receive an overriding royalty.
Transportation and processing fees decreased 18% for the year ended December 31, 2013, when compared
to the same period in 2012. The decrease in revenue was due to lower tonnage put through our all our facilities
except Sugar Camp and the sale of one of our processing facilities.
62
Minimums recognized as revenue decreased $16.5 million or 72% for the year ended December 31, 2013
when compared to the same period in 2012, primarily due to two lessees having significant previously paid
minimums losing the ability to recoup them during 2012 that did not occur in 2013.
We recorded a reserve swap for the year ended December 31, 2013 of $8.1 million on our Illinois property.
No swap occurred during 2012.
Wheelage revenue decreased by 29% for the year ended December 31, 2013 compared to the same period in
2012. This decrease was due to the normal fluctuations of tonnage that are subject to wheelage charges.
Aggregates and Industrial Minerals Revenues, and Other Related Income
For the Years Ended
December 31,
2013
2012
Increase
(Decrease)
Percentage
Change
(In thousands, except percent and per ton data)
(Unaudited)
Aggregates and industrial minerals related revenues . . . . . . . . . . .
$13,479 $9,524
$3,955
42%
Soda ash revenues and distributions:
Equity and other unconsolidated investment earnings . . . . . . . . . . .
Cash distributions received from OCI Wyoming . . . . . . . . . . . . . . .
$34,186
$72,946
N/A
N/A
N/A
N/A
N/A
N/A
Total aggregates and industrial minerals revenues, and other related income.
Total aggregates and
industrial minerals revenues, and other related income represented approximately 4% and 3% of our total
revenues and other income for the year ended December 31, 2013 and 2012, respectively. The following is a
discussion of the major categories of these revenues:
Aggregates and industrial minerals related revenues were up $4.0 million or 42% compared to 2012 due to
an increase of $1.2 million in minimums recognized as revenue during 2013. Override revenues also increased on
our frac sand properties by $1.6 million during the year ended December 31, 2013. This override was acquired
during the fourth quarter of 2012 and did not contribute until 2013.
Equity and other unconsolidated investment earnings.
Income from our investment in the OCI Wyoming
trona mining and soda ash production business was $34.2 million for the year ended December 31, 2013 and we
received $72.9 million in cash distributions which included a special distribution of $44.8 million during the year
ended December 31, 2013. We did not own this interest until January 2013.
Oil and Gas Revenues
Oil and gas revenues increased $7.5 million for the year ended December 31, 2013 when compared to the
same period in 2012. The increase is primarily due to revenues from our Williston Basin non-operated working
interest properties which were acquired during the second half of 2013.
Other Operating Results
Other Revenues.
In addition to coal related revenues, aggregates and industrial minerals revenues and oil
and gas revenues, we generated approximately 1% of our total revenues and other income from other sources for
the years ended December 31, 2014 and 2013 and less than 1% for 2012. Other sources of revenues primarily
include: rentals, metal revenue and timber royalties.
Operating expenses.
Included in total expenses are:
• Depreciation, depletion and amortization of $79.9 million, $64.4 million and $58.2 million for the years
ended December 31, 2014, 2013 and 2012, respectively. The increase in 2014 over 2013 is due to a full
year depletion on oil and gas acquisitions acquired in the fourth quarter of 2013 as well as depletion on the
Kaiser Francis oil and gas acquisition acquired during the second half of 2014. Also contributing to the
increase in depreciation, depletion and amortization is the added expense associated with the acquisition
63
of VantaCore in the fourth quarter of 2014. The increase in 2013 over 2012 is primarily due to increased
oil and gas depletion and higher coal depletion due to the reserve swap that occurred in 2013 being at a
higher per ton rate.
• General and administrative expenses of $36.4 million, $36.8 million and $29.7 million for the years ended
December 31, 2014, 2013 and 2012, respectively. General and administrative expenses are primarily
impacted by accruals under our long-term incentive plan attributable to fluctuations in our unit price and
additional personnel required to manage our properties. In 2014, we recorded additional expenses incurred
for the VantaCore and Kaiser Francis acquisitions, these costs were partially offset by lower accruals for
our long term incentive plan due to a drop in the unit price. In 2013, we recorded increases in both long
term incentive plan accruals and additional personnel over the two previous years.
• Property, franchise and other taxes of $21.3 million, $16.5 million and $17.7 million for the years ended
December 31, 2014, 2013 and 2012, respectively. The increase in property, franchise and other taxes
reflects the inclusion of severance tax from our oil and gas properties acquired in late 2013 and 2014. A
substantial portion of our property taxes in our coal and aggregates royalty business is reimbursed to us by
our lessees and is reflected as property tax revenue on our consolidated statements of comprehensive
income.
Interest Expense.
Interest expense was $80.2 million, $64.4 million and $54.0 million for the years ended
December 31, 2014, 2013 and 2012, respectively. Interest increased due to additional debt incurred in 2014 and
2013 to fund acquisitions as well as a refinancing of our credit facility and payment on our term loan with
9.125% high yield notes.
Liquidity and Capital Resources
Liquidity and Financing Activities
As of December 31, 2014, we had $100 million in available borrowing capacity under Opco’s revolving
credit facility and $27 million of available borrowing capacity under the NRP Oil and Gas revolving credit
facility. In addition to the amounts available under our revolving credit facilities, we had $50.1 million in cash at
December 31, 2014. Generally, we satisfy our working capital requirements with cash generated from operations.
We finance our acquisitions with available cash, borrowings under our revolving credit facilities, and the
issuance of debt securities and common units. We typically access the capital markets to refinance amounts
outstanding under our revolving credit facilities as we approach the limits under those facilities. Our current
liabilities exceeded our current assets by approximately $11.8 million as of December 31, 2014, because we used
cash to repay the principal on Opco’s notes rather than refinancing the amounts due.
As of December 31, 2014, we were in compliance with all of our debt covenant ratios. Opco’s revolving
credit facility and term loan facility both mature during 2016. In addition, we are required to make approximately
$81 million of principal payments in connection with Opco’s senior notes each year through 2018. We also have
$425 million principal amount of 9.125% senior notes issued by NRP and NRP Finance, as co-issurers, that
mature in 2018. In addition, we will be required to repay or refinance the amounts outstanding under Opco’s
credit facilities prior to their maturity. While we believe we will be able to refinance these amounts, we may not
be able to do so on terms acceptable to us, if at all, or the borrowing capacity under Opco’s revolving credit
facility may be substantially reduced. 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. In addition, our ability to refinance our debt may depend in part or our ability
to access the debt or equity capital markets, which will be challenging in the current market environment. For a
more complete discussion of factors that will affect our liquidity, see “Item 1A. Risk Factors—Risks Related to
Our Business.”
During 2014, we engaged in several financing transactions in connection with our two major acquisitions.
We funded the purchase price of VantaCore through the borrowing of $169.0 million under Opco’s revolving
credit facility and the issuance of 2,427,503 common units to certain of the sellers. We funded the $339 million
purchase price of the Sanish Field acquisition using a combination of the net proceeds of $100.4 million
64
(including our general partner’s proportionate capital contribution to maintain its 2% general partner interest in
us) from a public offering of 8,500,000 common units at a public offering price of $12.02 per common unit, the
net proceeds of $122.6 million from a private offering of an additional $125 million principal amount of our
9.125% Senior Notes due 2018 at an offering price of 99.5%, and borrowings of $117.0 million under the
amended NRP Oil and Gas revolving credit facility. Also during 2014, we sold 1,559,914 common units in
connection with our “at-the-market” offering program at an average price of $16.05 per common unit for
approximately $25.2 million in net proceeds, including our general partner’s proportionate capital contribution in
order to maintain its 2% general partner interest in us. We used the net proceeds from these sales for general
partnership purposes, including the repayment of principal due on Opco’s senior notes.
Capital Expenditures
Our capital expenditures, other than for acquisitions, have historically been minimal. However, as a result of
our Sanish Field oil and gas and VantaCore aggregates acquisitions in the fourth quarter of 2014, we anticipate
higher operating capital expenditures in 2015. A portion of the capital expenditures associated with both our oil
and gas working interest business and VantaCore are maintenance capital expenditures, which are capital
expenditures made to maintain the long-term production capacity of those businesses. These maintenance capital
expenditures reduce our cash available for distribution to our unitholders. We finance the capital expenditures
associated with our Williston Basin non-operated working interest oil and gas assets through a combination of
cash flow from operations and borrowings under the NRP Oil and Gas revolving credit facility and are able to
control the level of these capital expenditures by evaluating well proposals on a well-by-well basis. We will
continue to monitor the development programs of the operators of these properties and manage the capital
expenditures associated with those properties by only participating in wells that are expected to provide
acceptable economic returns. The capital expenditures in connection with VantaCore’s construction aggregates
mining and production operations are generally funded through cash flow from operations.
Cash Flows
Net cash provided by operating activities for the years ended December 31, 2014, 2013 and 2012 was
$210.8 million, $247.1 million and $271.4 million, respectively. The majority of our cash provided by operations
is generated from coal royalty revenues, our equity interest in OCI Wyoming and beginning in 2014, oil and gas
revenues.
Net cash used in investing activities for the years ended December 31, 2014, 2013 and 2012 was $520.5
million, $302.8 million and $212.7 million, respectively. Our 2014 investing activities consisted of our Sanish
Field oil and gas and VantaCore acquisitions, the $5.0 million Illinois Basin coal acquisition completed in June
2014, as well as additional capital expenditures related to the participation in new wells in connection with our
Williston Basin non-operated oil and gas working interest properties. Our 2013 investing activities consisted of
the acquisitions of the interest in OCI Wyoming and two acquisitions of non-operated working interests in oil
and gas properties located in the Williston Basin of North Dakota and Montana. During 2012, the majority of our
investing activities consisted of acquiring reserves, plant and equipment and related intangibles as well as assets
relating to Sugar Camp. These uses in 2012 were slightly offset by $24.8 million in proceeds from asset sales.
Net cash flows provided by financing activities for the year ended December 31, 2014 were $267.3 million.
Net cash flows used in financing activities for the years ended December 31, 2013 and 2012 were $1.2 million
and $124.2 million, respectively. During 2014, 2013 and 2012 we had proceeds from loans of $637.4 million,
$567.0 million and $148.0 million, respectively. During 2014, 2013 and 2012, these proceeds were offset by
repayment of debt of $328.0 million, $386.2 million and $30.8 million, respectively. Also during 2014, 2013 and
2012 we paid cash distributions to our unitholders of $162.0 million, $246.5 million and $238.0 million,
respectively. During 2014, we had net proceeds from an issuance of common units of $122.8 million, together
with a capital contribution from our general partner of $3.2 million. During 2013, we had net proceeds from an
issuance of common units of $74.7 million, together with a capital contribution from our general partner of $1.5
million.
65
Contractual Obligations and Commercial Commitments
NRP Debt
Senior Notes.
In September 2013, NRP and NRP Finance, as co-issuers, completed a private offering of
$300 million principal amount of 9.125% Senior Notes due 2018 at an offering price of 99.007% of par. The
notes were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act of
1933, as amended, and to persons outside the United States pursuant to Regulation S under the Securities Act.
The notes were issued pursuant to an indenture, dated September 18, 2013, among NRP, NRP Finance
Corporation and Wells Fargo Bank, National Association, as trustee. The notes bear interest at a rate of
9.125% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on April 1,
2014. The notes will mature on October 1, 2018.
In October 2014, NRP and NRP Finance issued an additional $125 million in aggregate principal amount of
the 9.125% Senior Notes due 2018 at an offering price of 99.5% of par. The notes were issued pursuant to the
existing indenture and constitute the same series of securities as the existing 9.125% Senior Notes due 2018
issued in September 2013. In the offering, $105 million in aggregate principal amount of the notes were sold in a
private offering to the initial purchasers thereof to be offered and sold to qualified institutional buyers pursuant to
Rule 144A under the Securities Act, and to persons outside the United States pursuant to Regulation S under the
Securities Act. The remaining $20 million in aggregate principal amount of the notes were sold in a separate
private offering to Cline Trust Company, LLC.
The notes are the senior unsecured obligations of NRP and NRP Finance. The notes rank equal in right of
payment to all existing and future senior unsecured debt of NRP and NRP Finance and senior in right of payment
to any subordinated debt of NRP and NRP Finance. The 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 will be structurally subordinated in right of payment to all existing and future debt and other
liabilities of NRP’s subsidiaries, including Opco’s revolving credit facility and term loan facility, each series of
Opco’s existing senior notes, and NRP Oil and Gas’s revolving credit facility. None of NRP’s subsidiaries
guarantee the notes.
NRP and NRP Finance have the option to redeem the notes, in whole or in part, at any time on or after
April 1, 2016, at the redemption prices (expressed as percentages of principal amount) of 106.844% for the six-
month period beginning on April 1, 2016, 104.563% for the twelve-month period beginning on October 1, 2016
and 100.000% beginning on October 1, 2017 and at any time thereafter, together with any accrued and unpaid
interest to the date of redemption. In addition, before April 1, 2016, NRP and NRP Finance may redeem all or
any part of the notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole
premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore,
before April 1, 2016, NRP and NRP Finance may on any one or more occasions redeem up to 35% of the
aggregate principal amount of the notes with the net proceeds of certain public or private equity offerings at a
redemption price of 109.125% of the principal amount of 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 notes issued under the 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 indenture, the holders of the
notes may require NRP and NRP Finance to purchase their notes at a purchase price equal to 101% of the
principal amount of the notes, plus accrued and unpaid interest, if any.
The indenture for the senior notes contains covenants that limit the ability of NRP and certain of its
subsidiaries to incur or guarantee additional indebtedness. Under the indenture, NRP 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 NRP and certain of its subsidiaries to incur additional indebtedness is further limited in the event
the amount of indebtedness of NRP and its subsidiaries that is senior to NRP’s unsecured indebtedness exceeds
certain thresholds. The indenture contains additional covenants that, among other things, limit NRP’s ability and
the ability of certain of its subsidiaries to declare or pay any dividend or distribution on, purchase or redeem units
66
or purchase or redeem subordinated debt; make investments; create certain liens; enter into agreements that
restrict distributions or other payments from NRP’s restricted subsidiaries as defined in the indenture to NRP;
sell assets; consolidate, merge or transfer all or substantially all of the assets of NRP and its restricted
subsidiaries; engage in transactions with affiliates; create unrestricted subsidiaries; and enter into certain sale and
leaseback transactions.
Opco Debt
As of the date of this filing, Opco’s debt consisted of:
• $200.0 million under the floating rate revolving credit facility, due August 2016;
• $75.0 million under the floating rate term loan, due January 2016;
• $18.5 million of 4.91% senior notes due 2018;
• $107.1 million of 8.38% senior notes due 2019;
• $46.2 million of 5.05% senior notes due 2020;
• $1.3 million of 5.31% utility local improvement obligation due 2021;
• $24.3 million of 5.55% senior notes due 2023;
• $67.5 million of 4.73% senior notes due 2023;
• $150.0 million of 5.82% senior notes due 2024;
• $45.5 million of 8.92% senior notes due 2024;
• $161.5 million of 5.03% senior notes due 2026; and
• $46.2 million of 5.18% senior notes due 2026.
Senior Notes. Opco issued the senior notes listed above under a note purchase agreement as supplemented
from time to time. The senior notes are unsecured but are guaranteed by Opco’s subsidiaries. Opco may prepay
the senior notes at any time together with a make-whole amount (as defined in the note purchase agreement). If
any event of default exists under the note purchase agreement, the noteholders will be able to accelerate the
maturity of the senior notes and exercise other rights and remedies.
The senior note purchase agreement contains 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 to consolidated fixed charges (consisting of consolidated
interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.
All of Opco’s senior notes require annual principal payments in addition to semi-annual interest payments.
Opco also makes annual principal and interest payments on the utility local improvement obligation.
Revolving Credit Facility. As of the date of this report, Opco had $100 million in available borrowing
capacity under its $300 million revolving credit facility, which matures on August 9, 2016.
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During 2014, Opco’s borrowings and repayments under its revolving credit facility were as follows:
March 31
June 30
September 30
December 31
Quarter Ending
(In thousands)
Outstanding balance, beginning of period . . . . . .
Borrowings under credit facility . . . . . . . . . . . . . .
Less: Repayments under credit facility . . . . . . . .
$20,000
—
—
$20,000
—
(5,000)
$15,000
—
(8,000)
$
7,000
394,000
(201,000)
Outstanding balance, ending period . . . . . . . . . . .
$20,000
$15,000
$ 7,000
$ 200,000
Opco’s obligations under its revolving credit facility are unsecured but are guaranteed by its subsidiaries.
Opco may prepay all amounts outstanding under the credit facility at any time without penalty. Indebtedness
under Opco’s revolving credit facility bears interest, at our option, at either:
• the Alternate Base Rate (as defined in the credit agreement) plus an applicable margin ranging from 0% to
1%; or
• the Adjusted LIBO Rate (as defined in the credit agreement) plus an applicable margin ranging from
1.00% to 2.25%.
Opco incurs a commitment fee on the unused portion of the revolving credit facility at a rate ranging from
0.18% to 0.40% per annum.
The Opco revolving credit facility contains covenants requiring Opco to maintain:
• a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to
exceed 4.0 to 1.0; and
• a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest
expense and consolidated lease operating expense) not less than 3.5 to 1.0.
Under an accordion feature in the credit facility, Opco may request its lenders to increase their aggregate
commitment to a maximum of $500 million on the same terms. However, Opco cannot be certain that its lenders
will elect to participate in the accordion feature. To the extent the lenders decline to participate, Opco may elect
to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be
available on existing or comparable terms.
Term Loan.
In connection with the OCI Wyoming soda ash business acquisition in January 2013, Opco
entered into a 3-year, $200 million term loan facility. The term loan facility is guaranteed by Opco’s operating
subsidiaries and bore interest at a weighted average rate of 2.22% in 2014. We repaid $101 million of the term
loan during 2013 and an additional $24 million in the fourth quarter of 2014. The remaining balance of $75.0
million is due on January 23, 2016. The term loan facility contains financial covenants and other terms that are
identical to those of Opco’s revolving credit facility.
NRP Oil and Gas Debt
Revolving Credit Facility.
In August 2013, NRP Oil and Gas entered into 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 owns non-operated working interests. In connection with the closing of the Sanish
Field acquisition in November 2014, the credit facility was amended to be a $500 million facility with an initial
borrowing base of $137 million and will mature on November 12, 2019. The credit facility is secured by a first
priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas is the
sole obligor under its revolving credit facility, and neither NRP nor any of its other subsidiaries is a guarantor of
such facility. As of December 31, 2014, NRP Oil and Gas had $110.0 million outstanding under the facility.
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Indebtedness under the NRP Oil and Gas credit facility bears interest, at the option of NRP Oil and Gas, at
either:
• 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 0.50% to 1.50%; or
• a rate equal to LIBOR, plus an applicable margin ranging from 1.50% to 2.50%.
NRP Oil and Gas incurs a commitment fee on the unused portion of the borrowing base under the credit
facility at a rate ranging from 0.375% to 0.50% per annum.
The NRP Oil and Gas credit facility contains certain covenants, which, among other things, require the
maintenance of (i) a total leverage ratio (defined as the ratio of the total debt of NRP Oil and Gas to its
EBITDAX) of not more than 3.5 to 1.0 and (ii) a current ratio of at least 1.0 to 1.0. The credit facility also
contains other customary covenants, subject to certain agreed exceptions, including covenants restricting the
ability of NRP Oil and Gas to, among other items, incur indebtedness; create, assume or permit to exist liens; be
a party to or be liable on any hedging contract; engage in mergers or consolidations; transfer, lease, exchange,
alienate or dispose of material assets or properties; pay distributions; make any acquisitions of, capital
contributions to or other investments in any entity or property; extend credit or make advances or loans; or
engage in transactions with affiliates. Events of default under the credit facility include payment defaults,
misrepresentations and breaches of covenants by NRP Oil and Gas. The credit facility also contains a cross-
default provision with respect to any indebtedness of NRP’s.
The maximum amount available under the credit facility is subject to semi-annual redeterminations of the
borrowing base in May and November of each year, based on the value of the proved oil and natural gas reserves
of NRP Oil and Gas, in accordance with the lenders’ customary procedures and practices. NRP Oil and Gas and
the lenders each have a right to one additional redetermination each year.
Long-Term Contractual Obligations
The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2014:
Contractual Obligations
Total
2015
2016
2017
2018
2019
Thereafter
Payments Due by Period
(In millions)
NRP:
Long-term debt principal payments
(including current maturities)(1) . . . . .
. . .
Long-term debt interest payments(2)
NRP Oil and Gas:
$ 425.0 $ — $ — $ — $425.0
38.8
155.2
38.8
38.8
38.8
$ — $ —
—
—
Long-term debt principal payments . . . . .
110.0
—
—
—
— 110.0
—
Opco:
Long-term debt principal payments
(including current maturities)(3) . . . . .
Long-term debt interest payments(4)
. . .
Rental leases(5) . . . . . . . . . . . . . . . . . . . .
943.1
187.0
2.7
81.0
38.4
0.7
356.0
33.3
0.7
81.0
28.2
0.7
81.0
23.2
0.6
76.4
18.2
—
267.7
45.7
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,823.0 $158.9 $428.8 $148.7 $568.6 $204.6
$313.4
(1) On September 18, 2013, NRP and NRP Finance issued $300 million of 9.125% senior notes at an offering
price of 99.007% of par value due October 1, 2018. On October 17, 2014 NRP and NRP Finance issued an
additional $125 million of 9.125% senior notes at an offering price of 99.5% of par value.
(2) The amounts indicated in the table include interest due on NRP’s 9.125% senior notes.
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(3) The amounts indicated in the table include principal due on Opco’s senior notes, credit facility, term loan
and utility local improvement obligation.
(4) The amounts indicated in the table include interest due on Opco’s senior notes and utility local improvement
obligation.
(5) On January 1, 2009, Opco entered into a ten-year lease agreement for the rental of office space from
Western Pocahontas Properties Limited Partnership for $0.6 million per year. In addition, BRP leases office
space for approximately $100,000 per year through 2017. These rental obligations are included in the table
above.
Shelf Registration Statements and “At-the-Market” Program
In April 2012 we filed an automatically effective shelf registration statement on Form S-3 with the SEC that
is available for registered offerings of common units and debt securities. In October 2014, we issued 8,500,000
common units in an underwritten public offering pursuant to this registration statement at a public offering price
of $12.02 per common unit. We used the net proceeds of approximately $100.4 million from this offering,
including our general partner’s proportionate capital contribution to maintain its 2% general partner interest in us,
to fund a portion of the purchase price of the Sanish Field acquisition.
In August 2012, we filed a shelf registration statement on Form S-3 that registered all of the common units
held by Adena Minerals. This shelf registration statement was declared effective by the SEC in September 2012.
Following the effectiveness of this registration statement, Adena distributed 15,181,716 common units to its
shareholders, and we subsequently filed prospectus supplements to register the resale of these common units by
those shareholders. The shelf registration statement filed in August 2012 also registered up to $500 million in
equity securities to be sold by NRP. In November 2013, we filed a prospectus supplement and entered into an
Equity Distribution Agreement relating to the offer and sale from time to time of common units having an
aggregate offering price of $75 million through one or more managers acting as sales agents at prices to be
agreed upon at the time of sale. Under the terms of the Equity Distribution Agreement, we may also sell common
units from time to time to any manager as principal for its own account at a price to be agreed upon at the time of
sale. Any sale of common units to any manager as principal would be pursuant to the terms of a separate terms
agreement between NRP and such manager. Sales of common units in this “at-the-market” (“ATM”) program are
made pursuant to the shelf registration statement declared effective in September 2012. For the year ended
December 31, 2014, we sold 1,559,914 common units for an average price of $16.05 for gross proceeds of $25.0
million.
In April 2013, we filed a resale shelf registration statement on Form S-3 to register the 3,784,572 common
units issued in the January 2013 private placement in connection with the OCI Wyoming acquisition. This shelf
registration statement was declared effective by the SEC in May 2013. A portion of the common units issued in
the private placement were issued, directly and indirectly, to certain of our affiliates, including Corbin J.
Robertson, Jr. and Christopher Cline.
We cannot control the resale of the common units by any of the selling unitholders under the shelf
registration statements described above, and the amounts, prices and timing of the issuance and sale of any equity
or debt securities by NRP will depend on market conditions, our capital requirements and compliance with our
credit facilities, term loan and senior notes.
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, 2014, 2013 and 2012.
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Environmental
The operations our lessees conduct on our properties, as well as the aggregates/industrial minerals and oil
and gas operations in which we have 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, we may be liable for certain environmental conditions occurring on the surface properties. The
terms of substantially all of our 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 us
against, among other things, environmental liabilities. Some of these indemnifications survive the termination of
the lease. We make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with
all regulations rests with the lessees. We believe that our lessees will be able to comply with existing regulations
and do not expect any lessee’s failure to comply with environmental laws and regulations to have a material
impact on our financial condition or results of operations. We have neither incurred, nor are aware of, any
material environmental charges imposed on us related to our properties for the period ended December 31, 2014.
We are not associated with any environmental contamination that may require remediation costs. However, our
lessees do conduct reclamation work on the properties under lease to them. Because we are not the permittee of
the mines being reclaimed, we are not responsible for the costs associated with these reclamation operations. In
addition, West Virginia has established a fund to satisfy any shortfall in reclamation obligations. As an owner of
working interests in oil and natural gas operations, we are responsible for our proportionate share of any losses
and liabilities, including environmental liabilities, arising from uninsured and underinsured events. We are also
responsible for losses and liabilities, including environmental liabilities that may arise from uninsured and
underinsured events.
For additional information on environmental regulation that may have a material impact on our business, see
“—Executive Overview—Political, Legal and Regulatory Environment Affecting Our Coal Business” and
“Item 1. Business—Regulation and Environmental Matters.”
Related Party Transactions
Partnership Agreement
Our 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, we reimburse our
general partner and its affiliates for expenses incurred on our behalf. All direct general and administrative
expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including
certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and
other corporate services incurred by our general partner and its affiliates.
The reimbursements to our general partner for services performed by Western Pocahontas Properties and
Quintana Minerals Corporation are as follows:
Reimbursement for services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,798
(In thousands)
$11,480
$9,791
For additional information, see “Item 13. Certain Relationships and Related Transactions, and Director
For the Years Ended
December 31,
2014
2013
2012
Independence—Omnibus Agreement.”
Transactions with Cline Affiliates
Various companies controlled by Chris Cline, including Foresight Energy LP, lease coal reserves from NRP,
and we provide coal transportation services to them for a fee. Mr. Cline, both individually and through affiliated
companies, owns a 31% interest in our general partner, as well as 4,917,548 common units, at the time of this
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filing. At December 31, 2014, we had accounts receivable totaling $9.2 million from Cline affiliates. In addition,
the overriding royalty and the lease of the loadout facility at the Sugar Camp mine are classified as contracts
receivable of $50.0 million on our Consolidated Balance Sheets. Revenues from the Cline affiliates are as
follows:
Coal royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Processing and transportation fees . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimums recognized as revenue . . . . . . . . . . . . . . . . . . . . . . . . . . .
Override revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For The Years Ended
December 31,
2014
2013
2012
$52,415
20,594
—
2,847
5,690
(In thousands)
$54,322
19,258
3,477
3,226
8,149
$48,567
21,923
17,785
4,066
—
$81,546
$88,432
$92,341
As of December 31, 2014, we had received $86.8 million in minimum royalty payments that have not been
recouped by Cline affiliates, of which $16.0 million was received in 2014.
During the fourth quarter of 2012, we recognized an impairment of $2.6 million related to the assets at the
Gatling West Virginia location, a location leased to and affiliate of Chris Cline.
During 2014 and 2013, we recognized non-cash gains of $5.7 million and $8.1 million on reserve exchanges
in Illinois with Williamson Energy, a subsidiary of Foresight Energy LP. The tons received during 2014 and
2013 were fully mined during each of those years, while the tons exchanged are not included in current mine
plans. The gains are included in Coal related revenues on the Consolidated Statement of Comprehensive Income.
We entered into a lease agreement related to the rail loadout and associated facilities at Sugar Camp that has
been accounted for as a direct financing lease. Total projected remaining payments under the lease at
December 31, 2014 are $86.3 million with unearned income of $39.0 million. The net amount receivable under
the lease as of December 31, 2014 was $47.3 million, of which $1.8 million is included in Accounts receivable—
affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying
Consolidated Balance Sheets.
In a separate transaction, we acquired a contractual overriding royalty interest from a Cline affiliate that
provides for payments based upon production from specific tons at the 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, 2014 was $5.6 million, of which $1.1 million is included in
Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on
the accompanying Consolidated Balance Sheets.
Note to Cline Trust Company, LLC
Donald R. Holcomb, one of our directors, is a manager of Cline Trust Company, LLC, which owns
approximately 5.35 million of our common units and $20 million in principal amount of our 9.125% Senior
Notes due 2018. 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. Cline Trust Company, LLC purchased the $20
million of our 9.125% Senior Notes due 2018 in our offering of $125 million additional principal amount of such
notes in October 2014 at the same price as the other purchasers in that offering. The balance on this portion of
our 9.125% Senior Notes due 2018 was $19.9 million as of December 31, 2014 and is included with our long
term debt.
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Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private
equity funds focused on investments in the energy business. In connection with the formation of Quintana
Capital, the Partnership 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 governance documents of Quintana Capital’s
affiliated investment funds reflect the guidelines set forth in NRP’s conflicts policy. See “Item 13. Certain
Relationships and Related Transactions, and Director Independence—Quintana Capital Group GP, Ltd.”
A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA,
LLC, including the right to nominate two members of Taggart’s 5-person board of directors. In 2013, Taggart
was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. We own and lease
preparation plants to Forge, which operates the plants. The lease payments were based on the sales price for the
coal that was processed through the facilities.
For the years ended December 31, 2014, 2013 and 2012, the revenues from Taggart prior to the sale to
Forge were as follows:
For the Years Ended
December 31,
2014
2013
2012
(In thousands)
Processing revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$— $1,761
$5,580
During the third quarter of 2012, we sold a preparation plant back to Taggart Global for $12.3 million. We
received $10.5 million in cash and a note receivable from Taggart, payable over three years for the balance. We
recorded a gain of $4.7 million included in Other income or the Consolidated Statements of Income for 2012.
The net book value of the asset sold was $7.6 million. During 2013, the note receivable that we held was paid in
full.
At December 31, 2013, a fund controlled by Quintana Capital owned a majority 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. Revenues from Corsa are as
follows:
For the Years Ended
December 31,
2014
2013
2012
Coal royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,013
(In thousands)
$4,594
$3,486
NRP also had accounts receivable totaling $0.3 million from Corsa at each of December 31, 2013 and
December 31, 2014.
Office Building in Huntington, West Virginia
We lease an office building in Huntington, West Virginia from Western Pocahontas at market rates. The
terms of the lease were approved by our Conflicts Committee. We pay $0.6 million each year in lease payments.
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.
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. We estimate that over 65% of our
coal is currently sold by our lessees under coal supply contracts that have terms of one year or more. Current
73
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.
The market price of soda ash directly affects the profitability of OCI Wyoming’s operations. If the market
price for soda ash declines, OCI 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. In addition, crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor
changes in supply and demand. These markets will likely continue to be volatile in the future.
Interest Rate Risk
Our exposure to changes in interest rates results from borrowings under the Opco revolving credit facility,
the Opco term loan and the NRP Oil and Gas revolving credit facility, which are subject to variable interest rates
based upon LIBOR or the federal funds rate plus an applicable margin. Management monitors interest rates and
may enter into interest rate instruments to protect against increased borrowing costs. At December 31, 2014, we
had $385 million outstanding in variable interest debt. If interest rates were to increase by 1%, annual interest
expense would increase approximately $3.9 million, assuming the same principal amount remained outstanding
during the year.
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Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Ernst & Young LLP, independent registered public accounting firm . . . . . . . . . . . . . . . . . . . . . . .
Report of Deloitte & Touche, LLP, independent registered public accounting firm . . . . . . . . . . . . . . . . . . . .
Consolidated balance sheets as of December 31, 2014 and 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of comprehensive income for the years ended December 31, 2014, 2013 and
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of partners’ capital for the years ended December 31, 2014, 2013 and 2012 . . . . .
Consolidated statements of cash flows for the years ended December 31, 2014, 2013 and 2012 . . . . . . . . . .
Notes to consolidated financial statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
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77
78
79
80
81
82
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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, 2014 and 2013, and the related consolidated statements of comprehensive income, partners’ capital
and cash flows for each of the three years in the period ended December 31, 2014. 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 OCI Wyoming LLC (OCI Wyoming)
(a Limited Liability Company in which Natural Resource Partners L.P. owns a 49% interest). Natural Resource
Partners L.P.’s investment in OCI Wyoming constituted approximately $264 million and $269 million of Natural
Resource Partners L.P.’s assets as of December 31, 2014 and 2013, and total revenues of $41 million and $34
million for the two years in the period ended December 31, 2014. Those statements were audited by other
auditors whose report has been furnished to us. Our opinion, insofar as it relates to the amounts included for
Natural Resource Partners L.P., is based solely 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 other auditors provides 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.
and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2014, 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,
2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 27,
2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2015
76
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
OCI Wyoming LLC
Atlanta, Georgia
We have audited the accompanying balance sheets of OCI Wyoming LLC (the “Company”) as of
December 31, 2014 and 2013, and the related statements of operations and comprehensive income, members’
equity, and cash flows for the years then ended, and the related notes to the financial statements. 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). 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, 2014 and 2013, and the results of its operations and its cash flows for the years
then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
February 26, 2015
77
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit information)
December 31,
2014
December 31,
2013
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net of allowance for doubtful accounts . . . . . . . . . . . . . . . . . .
Accounts receivable — affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
$
50,076
66,455
9,494
5,814
4,279
$
92,513
33,737
7,666
—
1,691
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant and equipment, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mineral rights, net
Intangible assets, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity and other unconsolidated investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loan financing costs, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term contracts receivable — affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
136,118
25,243
60,093
1,781,852
60,733
264,020
13,905
50,008
52,012
740
135,607
24,340
26,435
1,405,455
66,950
269,338
11,502
51,732
—
497
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,444,724
$1,991,856
Current liabilities:
LIABILITIES AND PARTNERS’ CAPITAL
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable — affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued incentive plan expenses — current portion . . . . . . . . . . . . . . . . . . . . . . . . .
Property, franchise and other taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
32,416
950
80,983
7,048
8,318
18,216
$
8,659
391
80,983
8,341
7,830
17,184
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued incentive plan expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Partners’ capital:
147,931
160,260
6,554
4,905
10,679
1,394,240
123,388
142,586
10,526
—
14,341
1,084,226
Common units outstanding: (122,299,825 and 109,812,408) . . . . . . . . . . . . . . . . . .
General partner’s interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
709,019
12,245
(650)
(459)
606,774
10,069
324
(378)
Total partners’ capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
720,155
616,789
Total liabilities and partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,444,724
$1,991,856
The accompanying notes are an integral part of these financial statements.
78
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands, except per unit data)
For the Years Ended December 31,
2013
2014
2012
Revenues and other income:
Coal related revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aggregates related revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas related revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity and other unconsolidated investment income . . . . . . . . . . . . . . . . . . .
Property taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$226,724 $274,194 $343,352
9,524
13,479
9,561
17,080
—
34,186
15,273
15,416
1,437
3,762
54,124
59,566
41,416
13,609
4,313
Total revenues and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
399,752
358,117
379,147
Operating expenses:
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, franchise and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas lease operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aggregates operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal royalty and override payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
79,876
26,209
36,437
21,279
9,144
32,309
1,604
3,975
64,377
734
36,821
16,463
739
—
1,644
1,103
58,221
2,568
29,714
17,678
—
—
1,944
1,857
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
210,833
121,881
111,982
Income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense)
188,919
236,236
267,165
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(80,185)
96
(64,396)
238
(53,972)
162
Income before non-controlling interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
108,830
—
172,078
—
213,355
—
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$108,830 $172,078 $213,355
Net income attributable to:
General partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,177
$
3,442
$
4,267
Limited partners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$106,653 $168,636 $209,088
Basic and diluted net income per limited partner unit . . . . . . . . . . . . . . . . . . . .
$
0.94
$
1.54
$
1.97
Weighted average number of common units outstanding . . . . . . . . . . . . . . . . .
113,262
109,584
106,028
Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$108,749 $172,143 $213,405
The accompanying notes are an integral part of these financial statements.
79
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands, except unit data)
Balance at December 31, 2011 . . . . . . . . .
Distributions to unitholders . . . . . . . . . . . .
Distributions to non-controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . .
Costs associated with equity
transactions . . . . . . . . . . . . . . . . . . . . . .
Net income for the year ended
December 31, 2012 . . . . . . . . . . . . . . . .
Loss on interest hedge . . . . . . . . . . . . . . . .
Comprehensive income . . . . . . . . . . . . . . .
Common Units
Units
Amounts
General
Partner
Amounts
Non-
Controlling
Interest
Amounts
Accumulated
Other
Comprehensive
Income (Loss)
106,027,836
$ 629,253
— (233,263)
$10,517
(4,758)
$ 5,638
—
$(493)
—
—
—
—
(59)
— 209,088
—
—
—
—
—
—
4,267
—
—
(2,793)
—
—
—
—
—
—
—
50
50
Total
$ 644,915
(238,021)
(2,793)
(59)
213,355
50
213,405
Balance at December 31, 2012 . . . . . . . . .
106,027,836
$ 605,019
$10,026
$ 2,845
$(443)
$ 617,447
Issuance of common units . . . . . . . . . . . . .
Capital contribution . . . . . . . . . . . . . . . . . .
Cost associated with equity
transactions . . . . . . . . . . . . . . . . . . . . . .
Distributions to unitholders . . . . . . . . . . . .
Distributions to non-controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . .
Net income for the year ended
3,784,572
—
75,000
—
—
1,531
—
(293)
— (241,588)
—
(4,930)
—
—
—
—
—
—
—
(2,521)
December 31, 2013 . . . . . . . . . . . . . . . .
— 168,636
3,442
Interest rate swap from unconsolidated
investments . . . . . . . . . . . . . . . . . . . . . .
Loss on interest hedge . . . . . . . . . . . . . . . .
Comprehensive income . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
13
52
65
75,000
1,531
(293)
(246,518)
(2,521)
172,078
13
52
172,143
Balance at December 31, 2013 . . . . . . . . .
109,812,408
$ 606,774
$10,069
$
324
$(378)
$ 616,789
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 . . . . . . . . . . . . . . . . . . . . . . . . .
Net income for the year ended
10,059,914
127,202
—
2,427,503
—
31,604
—
—
3,240
—
(4,413)
— (158,801)
—
(3,241)
—
—
—
—
—
—
—
—
(974)
December 31, 2014 . . . . . . . . . . . . . . . .
— 106,653
2,177
Interest rate swap from unconsolidated
investments . . . . . . . . . . . . . . . . . . . . . .
Unrealized loss on investments . . . . . . . . .
Loss on interest hedge . . . . . . . . . . . . . . . .
Comprehensive income . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(96)
(25)
40
(81)
127,202
31,604
3,240
(4,413)
(162,042)
(974)
108,830
(96)
(25)
40
108,749
Balance at December 31, 2014 . . . . . . . . .
122,299,825
$ 709,019
$12,245
$ (650)
$(459)
$ 720,155
The accompanying notes are an integral part of these financial statements.
80
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
2014
2013
2012
Cash flows from operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to net cash provided by operating activities:
$ 108,830
$ 172,078
$ 213,355
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash interest charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash gain on reserve swap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity and other unconsolidated investment income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions of earnings from unconsolidated investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in operating assets and liabilities (net of effects of acquisitions):
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued incentive plan expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, franchise and other taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
79,876
3,328
(5,690)
(41,416)
43,005
(1,386)
26,209
748
(10,693)
(795)
(4,411)
1,032
17,674
(5,265)
(291)
64,377
2,200
(8,149)
(34,186)
24,113
(10,921)
734
—
6,826
(516)
2,197
6,919
19,240
2,284
(122)
58,221
605
—
—
—
(13,575)
2,568
—
(802)
(236)
1,909
(496)
11,684
(3,461)
1,636
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
210,755
247,074
271,408
Cash flows from investing activities:
Acquisition of land, coal, other mineral rights and related intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of equity interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of aggregates business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions from unconsolidated investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of plant and equipment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Return on direct financing lease and contractual override . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in direct financing lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(339,768)
(72,000)
— (293,085)
—
—
48,833
—
10,929
2,558
—
(168,978)
(16,258)
3,633
(2,454)
1,418
1,904
—
(180,534)
—
—
—
—
(681)
24,822
2,669
(59,009)
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(520,503)
(302,765)
(212,733)
Cash flows from financing activities:
Proceeds from loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from issuance of common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of obligation related to acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Costs associated with equity transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions to non-controlling interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital contribution by general partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
637,375
127,202
(5,094)
(327,983)
—
(4,413)
(162,042)
(974)
3,240
567,020
75,000
(9,209)
(386,230)
—
(293)
(246,518)
(2,521)
1,531
148,000
—
—
(30,800)
(500)
(59)
(238,021)
(2,793)
—
Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
267,311
(1,220)
(124,173)
Net (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(42,437)
92,513
(56,911)
149,424
(65,498)
214,922
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 50,076
$ 92,513
$ 149,424
Supplemental cash flow information:
Cash paid during the period for interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 76,155
$ 55,191
$ 53,842
Non-cash investing activities:
Units issued for acquisition of aggregate operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Note receivable related to sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash contingent consideration on equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 31,604
—
— $ 15,000
—
— $
—
1,808
—
The accompanying notes are an integral part of these financial statements.
81
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Organization
Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April
2002. The general partner of the Partnership is NRP (GP) LP (“NRP GP”), a Delaware limited partnership,
whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The
Partnership engages principally in the business of owning, managing and leasing a diversified portfolio of
mineral properties in the United States, including interests in coal, trona and soda ash, oil and gas, construction
aggregates, frac sand and other natural resources.
The Partnership’s coal reserves are located in the three major U.S. coal-producing regions: Appalachia, the
Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. The Partnership
does not operate any coal mines, but leases its coal reserves to experienced mine operators under long-term
leases that grant the operators the right to mine and sell its reserves in exchange for royalty payments. The
Partnership also owns and manages infrastructure assets that generate additional revenues, primarily in the
Illinois Basin.
The Partnership owns or leases aggregates and industrial minerals located in a number of states across the
country. The Partnership derives a small percentage of its aggregates and industrial mineral revenues by leasing
its owned reserves to third party operators who mine and sell the reserves in exchange for royalty payments.
However, the majority of the Partnership’s aggregates revenues come through its ownership of VantaCore
Partners LLC, which was acquired in October 2014. VantaCore specializes in the construction materials industry
and operates three hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal.
VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
The Partnership also owns a 49% non-controlling equity interest in a trona ore mining operation and soda
ash refinery in the Green River Basin, Wyoming. OCI 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, and
records the income in accordance with the equity method of accounting.
The Partnership also owns various interests in oil and gas properties that are located in the Williston Basin,
the Appalachian Basin, Louisiana and Oklahoma. The Partnership’s interests in the Appalachian Basin,
Louisiana and Oklahoma are minerals and royalty interests, while in the Williston Basin the Partnership owns
non-operated working interests.
The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries.
The Partnership owns its subsidiaries through two wholly owned operating companies: NRP (Operating) LLC
and NRP Oil and Gas LLC. NRP GP has sole responsibility for conducting its 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, five of whom must be independent 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
Reclassification
Certain reclassifications have been made to the Consolidated Statements of Comprehensive Income.
Amounts relating to prior year’s coal royalties, processing fees, transportation fees, minimums recognized as
revenue, override royalties and other have been reclassified into a single line item “Coal related revenues” on this
82
year’s Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s aggregates royalties,
processing fees, minimums recognized as revenue, override royalties and other have been reclassified into a
single line item “Aggregates related revenues” on this year’s Consolidated Statements of Comprehensive
Income. Amounts relating to prior year’s oil and gas revenues and minimums recognized as revenue have been
reclassified into a single line item “Oil and gas related revenues” on this year’s Consolidated Statements of
Comprehensive Income. The following is reclassification reconciliation:
For The Year Ended
December 31, 2013
For The Year Ended
December 31, 2012
As
Reported
As
Reclassified
As
Reported
Coal
Related
Revenues
Aggregates
Related
Revenues
Total
Coal
Related
Revenues
Total
As
Reclassified
Aggregates
Related
Revenues
Oil & Gas
Related
Revenues
$212,663 $212,663
$ — $260,734
$260,734
$ — $ —
34,186
7,643
5,049
17,977
17,080
15,416
8,285
13,499
26,319
—
—
4,542
17,977
—
—
6,528
10,372
22,112
—
7,643
507
—
—
—
1,757
3,127
445
—
6,598
8,299
19,513
9,160
15,273
23,956
15,527
20,087
—
—
7,841
19,513
—
—
23,029
13,979
18,256
—
6,598
458
—
—
—
526
1,548
394
—
—
—
—
9,160
—
401
—
—
Revenues:
Coal royalties . . . . . . . . . . .
Equity and other
unconsolidated
investment income . . . . .
Aggregate royalties . . . . . . .
Processing fees . . . . . . . . . .
Transportation fees . . . . . . .
Oil and gas royalties . . . . . .
Property taxes . . . . . . . . . . .
Minimums recognized as
revenue . . . . . . . . . . . . . .
Override royalties . . . . . . . .
Other . . . . . . . . . . . . . . . . . .
Total revenues . . . . . . . . . . .
$358,117 $274,194
$13,479
$379,147 $343,352
$9,524
$9,561
Principles of Consolidation
The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned
subsidiaries, as well as BRP LLC, a joint venture with International Paper Company controlled by the
Partnership. Intercompany transactions and balances have been eliminated.
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.
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.
83
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 11. 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.
• 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.
Accounts are charged off when collection efforts are complete and future recovery is doubtful.
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 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20 to 40
5 to 12
Life of Lease
Years
84
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.
Mineral Rights
Mineral rights owned and leased are initially recorded using the FASB’s business combination and asset
purchase authoritative guidance depending on circumstances. 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. The Partnership owns royalty and non-operated working
interests in oil and natural gas minerals, all of which are located in the U.S. The Partnership does not determine
whether or when to develop reserves. The Partnership uses the successful efforts method to account for its
working interest in oil and gas properties. Oil and gas non-operated working interests are depleted on a unit-of-
production basis. The depletion rate is adjusted annually based upon the amount of remaining reserves as
determined by independent third party petroleum engineers. Oil and gas royalty interests are depleted on a
straight-line basis over 30 years or the life of the asset, whichever is shorter.
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.
Equity Investments
The Partnership accounts for non-marketable investments using the equity method of accounting if the
investment gives it the ability to exercise significant influence over, but not control of, an investee. Significant
influence generally exists if the Partnership has an ownership interest representing between 20% and 50% of the
voting stock of the investee.
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 fair value of the underlying net assets of equity method
investees 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.
The Partnership’s carrying value in an equity method investee company is reflected in the caption “Equity
and other unconsolidated investments” in the Partnership’s Consolidated Balance Sheets. The Partnership’s
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.” These earnings are generated from natural resources, which are considered part of the
Partnership’s core business activities consistent with its directly owned revenue generating activities. 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 book value, 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.
85
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.
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.
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. As a result of the continued weakness in the coal markets and
the potential for further declines in oil and natural gas prices, the Partnership intends to closely monitor its coal
and oil and gas assets and the impairment evaluation process may be completed more frequently if deemed
necessary by the Partnership. Future impairment analyses could result in downward adjustments to the carrying
value of the Partnership’s assets.
The Partnership evaluates its equity investments 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. No impairment losses have been recognized for equity investments as of December 31,
2014.
In accordance with accounting and disclosure guidance for goodwill, the Partnership tests its recorded
goodwill for impairment annually or more often if indicators of potential impairment exist, by determining if the
carrying value of a reporting unit exceeds its estimated fair value. Factors that could trigger an interim
impairment test include, but are not limited to, underperformance relative to historical or projected future
operating results or significant changes in the reporting units, business, industry, or economic trends.
Share-Based Payment
The Partnership accounts for awards relating to its 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 service or vesting 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. See
“Note 16. Incentive Plans.”
Deferred Revenue
Most of the Partnership’s coal and aggregates lessees must make minimum annual or quarterly payments
which are generally recoupable over certain time periods. These minimum payments are recorded as deferred
revenue when received. The deferred revenue attributable to the minimum payment is recognized as revenue
based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in
the period immediately following the expiration of the lessee’s ability to recoup the payments.
86
Asset Retirement Costs and Obligations
The Partnership accrues for mine closure, reclamation as well as plugging and abandonment of its oil and
gas non-operated working interests in accordance with authoritative guidance related to accounting for asset
retirement and environmental obligations. This guidance requires the fair value of an obligation be recognized in
the period it is incurred, if the fair value can be reasonably estimated. The Partnership recognizes an asset and
liability related to the present value of future estimated costs. Depreciation or depletion of the capitalized asset
retirement cost is determined based upon the underlying asset being retired in the future. Accretion of the asset
retirement obligation is recognized over time and will increase as the obligation becomes more near term. It is
reasonably possible that the estimates related to asset retirement and environmental obligations may change in
the future. See “Note 13. Asset Retirement Obligations.”
Revenues
Coal related revenues. Coal related revenue consist primarily of royalties as well as transportation and
processing fees. Royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees
and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership 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 the Partnership’s lessees and
the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to
the Partnership 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. 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.
Oil and Gas Revenues. Oil and gas related revenues consist of non-operated working interests, royalties
and overriding royalties. Revenues related to the Partnership’s non-operated working interests in oil and gas
assets are recognized based on the amount actually sold. The Partnership also has capital expenditure and
operating expenditure obligations associated with the non-operated working interests. The Partnership’s revenues
fluctuate based on changes in the market prices for oil and natural gas, the decline in production from producing
wells, and other factors affecting the third-party oil and natural gas exploration and production companies that
operate the wells, including the cost of development and production. 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. Some leases are subject to minimum annual payments or delay rentals.
Aggregates and Industrial Minerals Related Revenues. Aggregates and industrial minerals related
revenues consist primarily of revenues generated by VantaCore’s construction aggregates business, royalties and
overriding royalties. 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 at either
market or contractual prices. Aggregates royalty and overriding royalty revenues are recognized on the basis of
tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the
lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed
price per ton of mineral they sell. 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.
87
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 Property taxes revenue and in Property, franchise
and other taxes expense, respectively, in the Consolidated Statements of Comprehensive Income.
Transportation Revenue and Expense
Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as
Aggregate related revenues and Aggregates operating expenses in the Consolidated Statements of
Comprehensive Income.
Income Taxes
No provision for income taxes related to the operations of the Partnership has been included in the
accompanying financial statements because, as a partnership, it is not subject to federal or material state income
taxes and the tax effect of its activities accrues to the unitholders. 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.
New Accounting Standards
In May 2014, the FASB amended revenue recognition topics and created a new topic relating to revenue
recognition that will supersede existing guidance under U.S. GAAP. The core principle of the new guidance is to
recognize revenue when promised goods or services are transferred to the customer and in an amount that reflects
the consideration expected in exchange for those goods or services. To achieve this core principle, an entity
should (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract,
(3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the
contract and (5) recognize revenue when each performance obligation is satisfied. The guidance also specifies the
accounting for some costs to obtain or fulfill a contract with a customer. Disclosure requirements include
sufficient qualitative and quantitative information to enable financial statement users to understand the nature,
amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. The new topic
is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that
reporting period. The guidance allows for either full adoption or a modified retrospective adoption. The
Partnership is currently evaluating the requirements to determine the impact, if any, of this new topic on its
financial position, results of operations and cash flows.
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not
expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.
88
3. Significant Acquisitions
VantaCore. Consistent with the Partnership’s diversification plan, on October 1, 2014, the Partnership
completed its acquisition of VantaCore Partners LLC (“VantaCore”), a privately held company specializing in
the construction materials industry, for $201 million in cash and common units. Headquartered in Philadelphia,
Pennsylvania, VantaCore operates three hard rock quarries, five sand and gravel plants, two asphalt plants and a
marine terminal. VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee,
Kentucky and Louisiana.
Transaction costs through December 31, 2014 associated with this acquisition were $2.9 million and were
expensed as incurred. These expenses are reflected in General and administrative expense on the Consolidated
Statements of Comprehensive Income. Included in the consolidated statements of comprehensive income for the
year ended December 31, 2014 were revenue of $42.1 million and operating expenses of $32.3 million, including
depreciation and depletion of $3.2 million.
The Partnership accounted for the transaction in accordance with the authoritative guidance for business
combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition
date of October 1, 2014. The following table summarizes the purchase price and the preliminary estimated values
of assets acquired and liabilities assumed and are subject to revision as the Partnership continues to complete
appraisals of the fair value of the assets acquired and liabilities assumed. The preliminary allocation was based
on the book values of the assets and liabilities assumed with the excess of purchase price over net book value
allocated to goodwill. Adjustments to the estimated fair values may be recorded during the allocation period, not
to exceed one year from the date of acquisition.
Preliminary Purchase Price Allocation—VantaCore Partners LLC Acquisition
October 1, 2014
(In thousands)
Consideration
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NRP common units(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$168,978
31,604
Total consideration given . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$200,582
Preliminary Allocation of Purchase Price
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Land, property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mineral rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill
$ 37,222
40,411
87,907
3,268
(16,953)
(3,285)
52,012
Fair value of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$200,582
(1)
Includes 2,426,690 units issued on October 1, 2014 at $13.02, closing price on that day and 813 units issued
for a post-closing adjustment on December 4, 2014 at $10.48.
Sanish Field. Consistent with the Partnership’s diversification plans, in November 2014, the Partnership
completed the purchase of a 40% member interest in Kaiser-Whiting, LLC (“Kaiser LLC”) for $339 million,
subject to customary post-closing purchase price adjustments. Effective November 13, 2014, NRP Oil and Gas
withdrew as a member of Kaiser LLC and an undivided 40% interest in Kaiser LLC’s assets was distributed out
of Kaiser LLC, and assigned directly to the Partnership. The assets distributed to the Partnership included non-
operated working interests in approximately 6,086 net acres with an average working interest of approximately
14.5%. The assets, located in the Sanish Field in Mountrail County, North Dakota, are all held by production and
include 192 producing wells.
89
The transaction costs incurred in connection with this acquisition were $1.8 million through December 31,
2014, and were expensed as incurred. These expenses are reflected in General and administrative expense on the
Consolidated Statements of Comprehensive Income. Included in the consolidated statements of comprehensive
income for the year ended December 31, 2014, was revenue of $12.8 million and operating costs of $9.1 million
including depletion expense of $6.7 million related to the Sanish Field acquisition.
The Partnership accounted for the transaction in accordance with the authoritative guidance for business
combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition
date of November 12, 2014. The following table summarizes the preliminary purchase price and the preliminary
estimated values of assets acquired and liabilities assumed and are subject to revision as the Partnership
continues to complete appraisals of the fair value of the assets and liabilities assumed. Adjustments to the
estimated fair values may be recorded during the allocation period, not to exceed one year from the date of
acquisition.
Preliminary Purchase Price Allocation—Sanish Field Acquisition
Mineral rights
Proven oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Probable and possible resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total fair value of oil and gas properties acquired . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
November 12, 2014
(In thousands)
$298,627
40,800
339,427
(427)
Fair value of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$339,000
Pending the final purchase price adjustments and allocation, the net assets acquired of approximately $339.4
million are included in Mineral Rights in the accompanying Consolidated Balance Sheet. The acquisition
qualifies as a business combination, and as such, the Partnership estimated the fair value of each asset acquired
and liability assumed as of the acquisition date. Fair value measurements utilize assumptions of market
participants. To determine the fair value of the oil and gas assets, the Partnership used an income approach based
on a discounted cash flow model and made market assumptions as to future commodity prices, projections of
estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development
and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount
rates. The Partnership determined the appropriate discount rates used for the discounted cash flow analyses by
using a weighted average cost of capital from a market participant perspective plus reserve-specific risk
premiums for the assets acquired. The Partnership estimated reserve-specific risk premiums taking into
consideration that the related reserves are primarily oil, among other hydrocarbons. Given the unobservable
nature of some of the significant inputs, they are deemed to be Level 3 in the fair value hierarchy. The initial
estimate of asset retirement obligation liability was based upon historical information from Kaiser LLC.
Pro Forma Financial Information
As stated above, the Partnership completed the Sanish Field acquisition on November 13, 2014 and the
VantaCore acquisition on October 1, 2014. Below are the combined results of operations for the twelve months
ended December 31, 2014 and 2013 as if the acquisitions had occurred on January 1, 2013.
The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition
through the issuance of Partnership units and debt and additional depletion expense as a result of the Kaiser and
VantaCore acquisitions. The pro forma results do not include any cost savings or other synergies that may result from
the acquisition or any estimated costs that have been or will be incurred by the Partnership to integrate the properties
acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition
had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
90
For the Years ended
December 31,
2014
2013
(In thousands)
Revenue and other income except aggregate and oil and gas related
revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aggregates related revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas related revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$286,062
137,220
110,235
$327,558
152,032
100,343
Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$533,517
$579,933
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
Basic and diluted net income per limited partner unit
$122,319
0.99
$
$197,164
1.60
$
Sundance. On December 19, 2013, the Partnership completed the acquisition of non-operated working
interests in oil and gas properties in the Williston Basin of North Dakota from Sundance Energy, Inc. for $29.4
million, following post-closing purchase price adjustments. The Partnership accounted for the transaction in
accordance with the authoritative guidance for business combinations. During the third quarter of 2014, the
Partnership finalized the determination of the fair value of the assets acquired and liabilities assumed in the
acquisition, with no material adjustments. The assets acquired are included in Mineral rights in the
accompanying Consolidated Balance Sheets.
Abraxas. On August 9, 2013, the Partnership completed the acquisition of non-operated working interests
in oil and gas properties in the Williston Basin of North Dakota and Montana from Abraxas Petroleum for $38.0
million, following post-closing purchase price adjustments. The Partnership accounted for the transaction in
accordance with the authoritative guidance for business combinations. During the second quarter of 2014, the
Partnership finalized the determination of the fair values of the assets acquired and liabilities assumed in the
acquisition, with no material adjustments. The assets acquired are included in Mineral rights on the
accompanying Consolidated Balance Sheets.
With respect to the Abraxas and Sundance acquisitions, revenues of $36.1 million, capital expenditures of
$22.9 and operating expenses of $12.3 million were included in the Consolidated Statements of Comprehensive
Income and Consolidated Balance Sheet for the year ended December 31, 2014. For the year ended
December 31, 2013, revenues and total operating expenses from the Abraxas and Sundance acquisitions were
$5.4 million and $2.9 million, respectively.
4. Equity and Other Investments
The Partnership owns a 49% non-controlling equity interest in OCI Wyoming LLC (OCI Wyoming). The
investment was acquired from Anadarko Holding Company (Anadarko) and its subsidiary, Big Island Trona
Company for $292.5 million during 2013. OCI Wyoming’s operations consist of the mining of trona ore, which,
when refined, become soda ash. All soda ash is sold through an affiliated sales agent to various domestic and
European customers and to American Natural Soda Ash Corporation for export primarily to Asia and Latin
America. Included in fair value adjustments, is an increase in the Partnership’s proportionate fair value of
property, plant and equipment of $65.4 million, which will be depreciated using the straight-line method over a
weighted average life of 28 years. Also, $132.7 million has been assigned to a right to mine asset which will be
amortized using the units of production method. Under the equity method of accounting, these amounts are not
reflected individually in the accompanying consolidated financial statements but are used to determine periodic
charges to amounts reflected as income earned from the equity investment.
The acquisition agreement provides for a net present value of up to $50 million in cumulative additional
contingent consideration payable by the Partnership should certain performance criteria as defined in the
purchase and sale agreement be met by OCI Wyoming in any of the years 2013, 2014 or 2015. At December 31,
2014, the Partnership had accrued $14.5 million of contingent consideration that is included in Equity and other
91
unconsolidated investments. The current portion of $3.8 million is included in Accounts payable and accrued
liabilities and the long term portion of $10.7 million is included in Other non-current liabilities. During 2014 the
Partnership paid a $0.5 million payment for contingent consideration.
The table below summarizes the differences between the carrying amount of the Partnership’s investment
and the amount of the Partnership’s underlying equity in the net assets of OCI Wyoming. For both the twelve
month periods ended December 31, 2014 and 2013, the Partnership derived approximately 10% of its revenues
and other income from its equity investment in OCI Wyoming.
For the Year Ended
December 31,
2014
2013
(In thousands)
Net book value of NRP’s equity interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity and other unconsolidated investments . . . . . . . . . . . . . . . . . . . . . . . . . .
Excess of NRP’s investment over net book value of NRP’s equity interest . . .
Income allocation to NRP’s equity interests . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of basis difference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$101,311
$264,020
$162,709
$ 47,354
$ (5,938)
$ 96,692
$269,338
$172,646
$ 37,036
$ (2850)
Equity and other unconsolidated investment income . . . . . . . . . . . . . . . . . . . .
$ 41,416
$ 34,186
The following summarized financial information was taken from the OCI Wyoming-prepared financial
statements.
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Year Ended
December 31,
2014
2013
(In thousands)
$465,032
$118,439
$ 96,640
$200,622
$202,282
$ 47,704
$149,192
$442,132
$ 94,299
$ 79,655
$201,265
$194,508
$ 39,663
$158,779
5. Allowance for Doubtful Accounts
Activity in the allowance for doubtful accounts for the years ended December 31, 2014, 2013 and 2012 was
as follows:
Balance, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision charged to operations:
Additions to the reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Collections of previously reserved accounts . . . . . . . . . . . . . . . . . . . . . . .
Total charged (credited) to operations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-recoverable balances written off
2014
2013
2012
(In thousands)
$ 711
$ 275
$393
774
(373)
401
—
278
—
278
(714)
318
—
318
—
Balance, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 676
$ 275
$711
92
The Partnership acquired $0.5 million of allowances for doubtful accounts with its acquisition of
VantaCore.
6.
Inventory
The components of inventories at December 31, 2014 are as follows:
Aggregates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplies and parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
(In thousands)
$4,596
1,218
$5,814
All of the Partnership’s inventory for 2014 was acquired with its acquisition of VantaCore. For the year
ended December 31, 2013, the Partnership did not have inventory.
7. Plant and Equipment
The Partnership’s plant and equipment consist of the following:
December 31,
2014
December 31,
2013
Construction in process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant and equipment at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(In thousands)
457
89,759
(30,123)
$
—
55,271
(28,836)
Net book value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 60,093
$ 26,435
For the Years ended
December 31,
2014
2013
2012
Total depreciation expense on plant and equipment
. . . . . . . . . . . . . . . .
$7,631
(In thousands)
$5,966
$6,825
During the fourth quarter of 2014, the Partnership impaired a preparation plant. The impairment charge was
$0.8 million and is included in Asset impairments in the Consolidated Statements of Comprehensive Income for
the year ending December 31, 2014.
8. Mineral Rights
The Partnership’s mineral rights consist of the following:
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aggregates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depletion and amortization . . . . . . . . . . . . . . . . . . . . . .
December 31,
2014
December 31,
2013
(In thousands)
$1,541,572
560,395
211,490
15,014
(546,619)
$1,574,914
204,906
100,080
15,020
(489,465)
Net book value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,781,852
$1,405,455
93
For the years ended
December 31,
2014
2013
2012
Total depletion and amortization expense on mineral interests . . . . .
$68,603
(In thousands)
$54,595
$47,042
During its annual impairment analysis, the Partnership 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. While these conditions affect the Partnership’s ability to lease properties, other
events such as a lessee’s bankruptcy, a lease cancellation, lease modifications, a permanent idling of a property
could result in triggering events warranting further analysis. 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. The resulting impairment expense of $19.8 million relating to coal and aggregates
mineral properties is included in Asset impairments on the Consolidated Statements of Comprehensive Income.
9.
Intangible Assets
Amounts recorded as intangible assets along with the balances and accumulated amortization at
December 31, 2014 and 2013 are reflected in the table below:
Contract intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 82,972
3,004
(25,243)
$ 89,421
—
(22,471)
Net book value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 60,733
$ 66,950
December 31,
2014
December 31,
2013
(In thousands)
For the Years Ended
December 31,
2014
2013
2012
Total amortization expense on intangible assets . . . . . . . . . . . . . . . . . . .
$3,642
(In thousands)
$3,816
$4,354
Included in intangible assets are certain contract intangibles with a net book value of $1.3 million at
December 31, 2014 that were deemed held for sale. During the fourth quarter $52.0 million of goodwill was
added relating to the VantaCore acquisition. This amount represents the preliminary residual value and will be
adjusted as the Partnership continues complete appraisals of fair value relating to the acquisition.
During the second quarter of 2014, the Partnership and a lessee amended an aggregates lease, 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.
Estimated amortization expense (In thousands)
For year ended December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,486
3,743
3,326
3,126
3,053
94
10. Long-Term Debt
As used in this Note 10, references to “NRP LP” 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 and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned
subsidiary of NRP LP. NRP Finance Corporation (NRP Finance) is a wholly owned subsidiary of NRP LP and a co-
issuer with NRP LP on the 9.125% senior notes.
Long-term debt consists of the following:
NRP LP Debt:
$425 million 9.125% senior notes, with semi-annual interest payments in
April and October, maturing October 2018, $300 million issued at
99.007% and $125 million issued at 99.5% . . . . . . . . . . . . . . . . . . . . . . . .
Opco Debt:
$300 million floating rate revolving credit facility, due August 2016 . . . . . .
$200 million floating rate term loan, due January 2016 . . . . . . . . . . . . . . . . .
4.91% senior notes, with semi-annual interest payments in June and
December, with annual principal payments in June, maturing in June
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8.38% senior notes, with semi-annual interest payments in March and
September, with annual principal payments in March, maturing in March
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.05% senior notes, with semi-annual interest payments in January and July,
with annual principal payments in July, maturing in July 2020 . . . . . . . . .
5.31% utility local improvement obligation, with annual principal and
December 31,
2014
December 31,
2013
(In thousands)
$ 422,167
$ 297,170
200,000
75,000
20,000
99,000
18,467
23,084
107,143
128,571
46,154
53,846
interest payments, maturing in March 2021 . . . . . . . . . . . . . . . . . . . . . . . .
1,345
1,538
5.55% senior notes, with semi-annual interest payments in June and
December, with annual principal payments in June, maturing in June
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.73% senior notes, with semi-annual interest payments in June and
December, with scheduled principal payments beginning December
2014, maturing in December 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.82% senior notes, with semi-annual interest payments in March and
September, with annual principal payments in March, maturing in March
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8.92% senior notes, with semi-annual interest payments in March and
September, with scheduled principal payments beginning March 2014,
maturing in March 2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.03% senior notes, with semi-annual interest payments in June and
December, with scheduled principal payments beginning December
2014, maturing in December 2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.18% senior notes, with semi-annual interest payments in June and
December, with scheduled principal payments beginning December
2014, maturing in December 2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24,300
27,000
67,500
75,000
150,000
165,000
45,455
50,000
161,538
175,000
46,154
50,000
NRP Oil and Gas Debt:
Reserve-based revolving credit facility due 2019 . . . . . . . . . . . . . . . . . . . . . .
110,000
—
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less—current portion of long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,475,223
(80,983)
1,165,209
(80,983)
Long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,394,240
$1,084,226
95
NRP LP Debt
Senior Notes.
In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300 million
of 9.125% Senior Notes due 2018 at an offering price of 99.007% of par. Net proceeds after expenses from the
issuance of the senior notes of approximately $289.0 million were used to repay all of the outstanding
borrowings under Opco’s revolving credit facility and $91.0 million of Opco’s term loan. The senior notes call
for semi-annual interest payments on April 1 and October 1 of each year, beginning on April 1, 2014. The notes
will mature on October 1, 2018.
In October 2014, NRP LP, together with NRP Finance as co-issuer, issued an additional $125 million of its
9.125% Senior Notes due 2018 at an offering price of 99.5% of par. The notes constitute the same series of
securities as the existing $300.0 million 9.125% senior notes due 2018 issued in September 2013. Net proceeds
after expenses from the issuance of the Senior Notes of approximately $122.6 million 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 notes call for semi-annual interest payments as April 1 and October 1 of
each year, beginning on April 1, 2015. The notes will mature on October 1, 2018.
The indenture for the senior notes contains covenants that, among other things, limit the ability of the NRP
LP and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the indenture, NRP LP 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 NRP LP and certain of its subsidiaries to incur additional indebtedness is further
limited in the event the amount of indebtedness of NRP LP and certain of its subsidiaries that is senior to NRP
LP’s unsecured indebtedness exceeds certain thresholds.
Opco Debt
Senior Notes. Opco made principal payments of $80.8 million on its senior notes during the year ended
December 31, 2014. The Opco senior note purchase agreement contains 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 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% senior notes also provide that in the event that Opco’s leverage ratio 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.
Revolving Credit Facility. The weighted average interest rates for the debt outstanding under Opco’s
revolving credit facility for the twelve months ended December 31, 2014 and year ended December 31, 2013
were 1.98% and 2.23%, respectively. Opco incurs a commitment fee on the undrawn portion of the revolving
credit facility at rates ranging from 0.18% to 0.40% per annum. The facility includes an accordion feature
whereby Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on
the same terms.
Opco’s revolving credit facility contains covenants requiring Opco to maintain:
• a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to
exceed 4.0 to 1.0 and,
• a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest
expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent
quarters.
96
Term Loan Facility. During 2013, Opco issued $200 million in term debt. The weighted average interest
rates for the debt outstanding under the term loan for the twelve months ended December 31, 2014 and 2013
were 2.22% and 2.43% respectively. Opco repaid $101 million in principal under the term loan during the third
quarter of 2013 and an additional $24 million during the fourth quarter of 2014. Repayment terms call for the
remaining outstanding balance of $75 million to be paid on January 23, 2016. The debt is unsecured but
guaranteed by the subsidiaries of Opco.
Opco’s term loan contains covenants requiring Opco to maintain:
• a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to
exceed 4.0 to 1.0 and,
• a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest
expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent
quarters.
NRP Oil and Gas Debt
Revolving Credit Facility.
In August 2013, NRP Oil and Gas entered into a 5-year, $100 million 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 owns non-operated working interests. In connection with the
closing of the Sanish Field acquisition in November 2014, the credit facility was amended to be a $500 million
facility with an initial borrowing base of $137 million and will mature on November 12, 2019. The credit facility
is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP
Oil and Gas is the sole obligor under its revolving credit facility, and neither the Partnership nor any of its other
subsidiaries is a guarantor of such facility. At December 31, 2014, there was $110.0 million outstanding under
the credit facility. The weighted average interest rate for the debt outstanding under the credit facility for the
twelve months ended December 31, 2014 was 2.37%.
Indebtedness under the NRP Oil and Gas credit facility bears interest, at the option of NRP Oil and Gas, at
either:
• 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 0.50% to 1.50%; or
• a rate equal to LIBOR, plus an applicable margin ranging from 1.50% to 2.50%.
NRP Oil and Gas incurs a commitment fee on the unused portion of the borrowing base under the credit
facility at a rate ranging from 0.375% to 0.50% per annum.
The NRP Oil and Gas credit facility contains certain covenants, which, among other things, require the
maintenance of:
• a total leverage ratio (defined as the ratio of the total debt of NRP Oil and Gas to its EBITDAX) of not
more than 3.5 to 1.0; and
• a minimum current ratio of 1.0 to 1.0.
The maximum amount available under the credit facility is subject to semi-annual redeterminations of the
borrowing base in May and November of each year, based on the value of the proved oil and natural gas reserves
of NRP Oil and Gas, in accordance with the lenders’ customary procedures and practices. NRP Oil and Gas and
the lenders each have a right to one additional redetermination each year.
97
Consolidated Principal Payments
The consolidated principal payments due are set forth below:
NRP LP
Opco
NRP
Oil and Gas
Senior Notes
Senior Notes Credit Facility Term Loan Credit Facility
Total
$
2015 . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . .
— $ 80,983
80,983
—
80,983
—
80,983
76,366
267,758
—
—
425,000(1)
$
(In thousands)
— $ — $
75,000
—
—
—
—
200,000
—
—
—
—
— $
—
—
—
110,000
—
80,983
355,983
80,983
505,983
186,366
267,758
$425,000
$668,056
$200,000
$75,000
$110,000
$1,478,056
(1) The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2014 were carried at
$422.2 million.
NRP LP, Opco and NRP Oil and Gas were in compliance with all terms under their long-term debt as of
December 31, 2014. Opco’s revolving credit facility and term loan facility both mature in 2016. While the
Partnership believes it has sufficient liquidity to meet its current financial needs, the Partnership will be required
to repay or refinance the amounts outstanding under Opco’s credit facilities prior to their maturity. While the
Partnership believes it will be able to refinance these amounts, it may not be able to do so on terms acceptable to
them, if at all, or the borrowing capacity under Opco’s revolving credit facility may be substantially reduced. The
Partnership’s ability to refinance these amounts may depend in part on its ability to access the debt or equity
capital markets, which will be challenging in the current commodity price environment.
11. Fair Value Measurements
The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts
payable and long-term debt. The carrying amount of the Partnership’s financial instruments included in accounts
receivable and accounts payable approximates their fair value due to their short-term nature except for the
accounts receivable—affiliate relating to the Sugar Camp override that includes both current and long-term
portions. The Partnership’s cash and cash equivalents include money market accounts and are considered a
Level 1 measurement. The fair market value and carrying value of the contractual override and long-term senior
notes are as follows:
Fair Value As Of
Carrying Value As Of
December 31,
2014
December 31,
2013
December 31,
2014
December 31,
2013
(In thousands)
Assets
Sugar Camp override, current and
long-term . . . . . . . . . . . . . . . . . . . . .
$
5,162
$
6,852
$
4,870
$
6,063
Liabilities
Long-term debt, current and
long-term . . . . . . . . . . . . . . . . . . . . .
$1,096,520
$1,071,880
$1,090,223
$1,046,209
The fair value of the Sugar Camp override and long-term debt is estimated by discounting expected future
cash flows at a comparable term risk-free treasury interest rate plus a market rate component comparable to the
yield premium observed on debt securities of similar risk and maturity, which is a Level 3 measurement. Since
the Partnership’s credit facilities and term loan are variable rate debt, their fair values approximate their carrying
amounts.
98
12. Related Party Transactions
Reimbursements to Affiliates of the Partnership’s General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its
management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the
general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct
general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses
indirect general and administrative costs, including certain legal, accounting, treasury, information technology,
insurance, administration of employee benefits and other corporate services incurred by the Partnership’s general
partner and its affiliates. The Partnership had accounts payable of $0.4 million with Western Pocahontas
Properties and $0.6 million with Quintana Minerals Corporation.
The reimbursements to affiliates of the Partnership’s general partner for services performed by Western
Pocahontas Properties and Quintana Minerals Corporation are as follows:
Reimbursement for services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,798
(In thousands)
$11,480
$9,791
For the Years Ended
December 31,
2014
2013
2012
The Partnership leases an office building in Huntington, West Virginia from Western Pocahontas Properties
and pays $0.6 million in lease payments each year through December 31, 2018.
Transactions with Cline Affiliates
Various companies controlled by Chris Cline, including Foresight Energy LP, lease coal reserves from the
Partnership, and the Partnership provides coal transportation services to them for a fee. Mr. Cline, both
individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest (unaudited) in the
Partnership’s general partner, as well as 4,917,548 common units (unaudited) at December 31, 2014. At
December 31, 2014, the Partnership had accounts receivable totaling $9.2 million from Cline affiliates. In
addition, the overriding royalty and the lease of the loadout facility at the Sugar Camp mine are classified as
contracts receivable of $50.0 million on the Partnership’s Consolidated Balance Sheets. Revenues from the Cline
affiliates are as follows:
Coal royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Processing and transportation fees . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimums recognized as revenue . . . . . . . . . . . . . . . . . . . . . . . . . . .
Override revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For The Years Ended
December 31,
2014
2013
2012
$52,415
20,594
—
2,847
5,690
(In thousands)
$54,322
19,258
3,477
3,226
8,149
$48,567
21,923
17,785
4,066
—
$81,546
$88,432
$92,341
As of December 31, 2014, the Partnership had received $86.8 million in minimum royalty payments that
have not been recouped by Cline affiliates, of which $16.0 million was received during 2014.
During the fourth quarter of 2012, the Partnership recognized an asset impairment of $2.6 million related to
the assets at the Gatling, WV location, a location leased to an affiliate of Chris Cline, due to receiving a
termination notice in December 2012 that the lease was cancelled as of June 2013.
99
During 2014 and 2013, the Partnership recognized gains of $5.7 million and $8.1 million on reserve swaps
in Illinois with Williamson Energy, a subsidiary of Foresight Energy LP. The gains are reflected in the table
above in the “Other revenue” line. The fair value of the reserves was estimated using Level 3 cash flow approach.
The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and
anticipated market royalty rates. The tons received during 2014 and 2013 were fully mined during each of those
years, while the tons exchanged are not included in the current mine plans. The gains are located in Coal related
revenues on the Consolidated Statements of Comprehensive Income.
The Partnership entered into a lease agreement related to the rail loadout and associated facilities at Sugar
Camp that has been accounted for as a direct financing lease. Total projected remaining payments under the lease
at December 31, 2014 are $86.3 million with unearned income of $39.0 million. The net amount receivable under
the lease as of December 31, 2014 was $47.3 million, of which $1.8 million is included in Accounts receivable—
affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying
Consolidated Balance Sheets.
In a separate transaction, the Partnership acquired a contractual overriding royalty interest from a Cline
affiliate that provides for payments based upon production from specific tons at the 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, 2014 was $5.6 million, of which $1.1 million is
included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—
affiliate on the accompanying Consolidated Balance Sheets.
Note to Cline Trust Company, LLC
Donald R. Holcomb, one of the Partnership’s directors, is a manager of Cline Trust Company, LLC, which
owns approximately 5.35 million of the Partnership’s common units and $20 million in principal amount of the
Partnership’s 9.125% Senior Notes due 2018. 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. Cline Trust Company,
LLC purchased the $20 million of the Partnership’s 9.125% Senior Notes due 2018 in the Partnership’s offering
of $125 million additional principal amount of such notes in October 2014 at the same price as the other
purchasers in that offering. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was
$19.9 million as of December 31, 2014 and is included with the Partnership’s long term debt.
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. 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 NRP’s conflicts policy.
A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA,
LLC, including the right to nominate two members of Taggart’s 5-person board of directors. In 2013, Taggart
was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. The Partnership owns
and leases preparation plants to Forge, which operates the plants. The lease payments were based on the sales
price for the coal that was processed through the facilities.
For the years ended December 31, 2014, 2013 and 2012, the revenues from Taggart prior to the sale to
Forge were as follows:
Processing revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$— $1,761
$5,580
100
For the Years Ended
December 31,
2014
2013
2012
(In thousands)
During the third quarter of 2012, the Partnership sold a preparation plant back to Taggart Global for $12.3
million. The Partnership received $10.5 million in cash and a note receivable from Taggart, payable over three
years for the balance. The Partnership recorded a gain of $4.7 million included in Coal related revenues on the
Consolidated Statements of Income during 2012. The net book value of the asset sold was $7.6 million. During
2013, the note receivable that the Partnership held was paid in full.
At December 31, 2014, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal
Corp., 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.
Revenues from Corsa are as follows:
Coal royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,013
(In thousands)
$4,594
$3,486
At each of December 31, 2013 and 2014, the Partnership also had accounts receivable totaling $ 0.3 million
For the Years Ended
December 31,
2014
2013
2012
from Corsa.
13. Asset Retirement Obligations
The Partnership accrues a liability for legal asset retirement obligations based on an estimate of the timing
and amount of settlement. The Partnership accrues for costs involving the ultimate closure of certain of its
aggregate mining operations in accordance with its operating permits. These charges include costs of land
reclamation, water drainage, and incremental direct administration cost of closing the operations. The Partnership
also accrues for estimated costs relating to plugging wells in which it has a non-operation working interest. Upon
initial recognition of an asset retirement obligation the Partnership increases the carrying amount of the long-
lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their
present value, through charges to depreciation, depletion, and amortization and the initial costs are depleted over
the useful lives of the related assets.
The following table presents a reconciliation of the beginning and ending carrying amounts of the
Partnership’s asset retirement obligations. The table does not include the short-term balance of $68,000, which is
included in Accounts payable and accrued liabilities in the Consolidated Balance Sheets. The Partnership does
not have any assets that are legally restricted for purposes of settling these obligations.
Balance, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities incurred in current period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Years Ended
December 31,
2014
2013
$
(In thousands)
39
4,697
237
$39
—
—
Balance, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,973
$39
14. Commitments and Contingencies
Legal
The Partnership 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.
101
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, 2014. The Partnership is not associated with any 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. In
addition, West Virginia has established a fund to satisfy any shortfall in reclamation obligations. As an 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.
The Partnership is also responsible for losses and liabilities, including environmental liabilities that may arise
from uninsured and underinsured events.
15. Major Lessees
The Partnership has the following lessees that generated in excess of ten percent of total revenues in any one
of the years ended December 31, 2014, 2013, and 2012. Revenues from these lessees are as follows:
For the Years Ended December 31,
2014
2013
2012
Revenues
Percent
Revenues
Percent
Revenues
Percent
(Dollars in thousands)
Foresight Energy and affiliates . . . . .
Alpha Natural Resources . . . . . . . . .
$81,546
$48,783
20.4% $88,432
12.2% $55,147
24.7% $92,341
15.4% $81,077
24.4%
21.4%
In 2014, the Partnership derived 32.6% of its revenue from the two companies listed above. As a result, the
Partnership has a significant concentration of revenues with those lessees, although in most cases, with the
exception of the Williamson mine operated by Foresight Energy, the exposure is spread over a number of
different mining operations and leases. Foresight’s Williamson mine alone was responsible for approximately
10.2%, 13.0% and 12.4% of the Partnership’s total revenues for 2014, 2013 and 2012, respectively.
Approximately 50% of the Partnership’s accounts receivable result from amounts due from third-party
companies in the coal industry, with approximately 30% of the Partnership’s total revenues being attributable to
coal royalty revenues from Appalachia. This concentration of customers may impact the Partnership’s overall
credit risk, either positively or negatively, in that these entities may be collectively affected by the same changes
in economic or other conditions. Receivables are generally not collateralized.
16.
Incentive Plans
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
102
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.
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.
A summary of activity in the outstanding grants for the year ended December 31, 2014 are as follows:
Outstanding grants at the beginning of the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Grants during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Grants vested and paid during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeitures during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,012,984
454,884
(285,500)
(28,975)
Outstanding grants at the end of the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,153,393
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability
fluctuates with the market value of the Partnership common units and because of changes in estimated fair value
determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and historical
volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each
outstanding grant and ranged from 0.26% to 1.06% and 33.40% to 43.43%, respectively at December 31, 2014.
The Partnership’s cumulative average dividend rate of 7.46% was used in the calculation at December 31, 2014.
The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $1.0 million, $9.6
million and $2.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. In connection with
the Long-Term Incentive Plans, cash payments of $6.5 million, $7.0 million and $6.6 million were paid during
each of the years ended December 31, 2014, 2013, and 2012, respectively. The grant date fair value was $17.73,
$25.27 and $33.38 per unit for awards in 2014, 2013 and 2012, respectively.
In connection with the phantom unit awards, the CNG committee also granted tandem Distribution
Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on
the Partnership’s common units. The DERs are payable in cash upon vesting but may be subject to forfeiture if
the grantee ceases employment prior to vesting.
The unaccrued cost, associated with unvested outstanding grants and related DERs at December 31, 2014,
was $5.2 million.
17. Subsequent Events (Unaudited)
The following represents material events that have occurred subsequent to December 31, 2014 through the
time of the Partnership’s filing of its Annual Report on Form 10-K with the SEC:
Distributions
On January 20, 2015, the Partnership declared a distribution of $0.35 per unit that was paid on February 13,
2015 to unitholders of record on February 5, 2015.
Dividends and Distributions Received From Unconsolidated Equity and Other Investments
Subsequent to December 31, 2014, the Partnership received $10.9 million in cash distributions from OCI
Wyoming.
103
18. Supplemental Financial Data (Unaudited)
Shown below are selected unaudited quarterly data.
Selected Quarterly Financial Information
(In thousands, except per unit data)
2014
Total revenues and other income . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . . . . .
Asset impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income per limited partner unit . . . . . . . . . . . . . . .
Weighted average number of common units
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
— $
$ 80,309
$ 14,647
$
$ 52,439
$ 32,605
0.29
$
$ 90,561
$ 16,350
5,624
$ 50,403
$ 31,407
0.28
$
$ 91,609
$ 18,621
$
$ 55,027
$ 36,173
0.32
$
$137,273
$ 30,258
— $ 20,585
$ 31,050
8,645
$
0.07
$
outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
109,848
110,403
111,244
121,449
2013
Total revenues and other income . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on Department of Highway condemnation . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income per limited partner unit . . . . . . . . . . . . . . .
Weighted average number of common units
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$ 82,237
$ 86,804
$ 94,332
$ 17,852
$ 17,411
$ 14,762
$ 51,624
$ 55,332
$ 62,528
443
291
$
$
$
$
— $
— $
$ 47,906
0.43
$
$ 41,065
0.37
$
$ 36,126
0.32
$
$ 94,744
$ 14,352
$ 66,752
— $
—
— $ 10,370
$ 46,981
0.42
$
outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
108,887
109,812
109,812
109,812
104
19. Supplemental Oil and Gas Data (Unaudited)
The Partnership prepared the following oil and gas information in accordance with the authoritative
guidance for oil and gas extractive activities.
Capitalized Costs:
Proven properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproven properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible drilling costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wells and related equipment
Gathering assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Well plugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For The Year
Ended
December 31,
2014
(In Thousands)
$361,554
46,400
25,217
5,382
—
—
Total property, plant, and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation, depletion, and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
438,553
(18,993)
Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$419,560
Costs incurred for property acquisition, exploration, and development:
For the
Year Ended
December 31,
2014
(In thousands)
Property acquisitions
Proven properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproven properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$298,627
40,800
5,340
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$344,767
Results of Operations for Producing Activities:
Production revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Royalty and overriding royalty revenue(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total oil and gas related revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating costs and expense:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, franchise and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating costs and expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Year
Ended
December 31,
2014
(In thousands)
$48,834
10,732
59,566
23,936
3,400
5,529
9,144
42,009
Total income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$17,557
(1)
Includes $1.9 million of nonproduction revenues including lease bonus payments.
105
Production and Price History
The following table sets forth summary information concerning the Partnership’s production results,
average sales prices and production costs for the year ended December 31, 2014 for the Partnership’s Williston
Basin properties. Production and price information for the years ended December 31, 2013 and 2012 is not
included, as the Partnership’s oil and natural gas producing activities were not material to the Partnership’s
results of operations for those years.
For The Year Ended December 31,
2014
Royalty and
Overriding
Royalty
Interests(2)
Williston
Basin(1)
Net Production Volumes:
Crude oil (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average sales prices:
Crude oil ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGLs ($/Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average costs ($/Boe):
Production expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ad valorem and severance taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . .
DD&A expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
578
53
408
$77.85
$33.64
$ 5.04
$13.08
$ 7.91
$ 4.86
$25.73
33
18
1,313
$82.91
$34.56
$ 4.17
—
—
—
$22.06
Total
611
71
1,721
$78.12
$33.87
$ 4.37
$13.08
$ 7.91
$ 4.86
$24.70
(1) Represents volume, price and cost information relating to the Partnership’s non-operated Williston Basin
working interest properties.
(2) Represents information relating to the Partnership’s royalty and overriding royalty interests in oil and gas
properties. These interests are recorded net of costs.
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, 2014 were prepared by Netherland, Sewell & Associates, Inc., the Partnership’s independent
reserve engineer. To achieve reasonable certainty, Netherland Sewell employed technologies that have been
demonstrated to yield results with consistency and repeatability. The technologies and economic data 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 following tables set forth the Partnership’s estimated proved and related standardized measure of
discounted cash flows by reserve category as of December 31, 2014. Netherland Sewell prepared its report
covering properties representing 100% of the Partnership’s estimated proved reserves as of December 31, 2014.
Prices were calculated using the unweighted average of the first-day-of-the-month pricing for the twelve months
ended December 31, 2014. These prices were then adjusted for transportation and other costs. There can be no
106
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. A copy of Netherland Sewell’s summary
report is included as Exhibit 99.2 to this Annual Report on Form 10-K.
Proved Developed Producing . . . . . . . . . . . .
Proved Developed Non-Producing . . . . . . . .
Proved Undeveloped . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated Proved Reserves as of December 31, 2014(1)
Crude
Oil
(MBbl)
8,918
12
1,053
9,983
NGLs
(MBbl)
1,093
5
131
1,229
Natural
Gas
(MMcf)
13,069
92
1,209
14,370
Total
Proved
Reserves
(MBoe)(2)
12,189
32
1,386
Standardized
Measure of
Discounted
Cash Flows(3)
(in thousands)
$286,179
655
18,363
13,607(4)
$305,197
(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) Standardized measure of discounted cash flows represents the present value of estimated future net revenue
to be generated from the production of proved reserves, determined in accordance with the rules and
regulations of the SEC (using prices and costs in effect as of the date of estimation), less future
development, production and income tax expenses, and discounted at 10% per annum to reflect the timing
of future net revenue.
(4)
Includes 12,144 MBoe of estimated proved reserves attributable to the Partnership’s non-operated working
interests in oil and natural gas properties in the Williston Basin, approximately 10% of which were proved
undeveloped reserves.
The following table represents the capitalized development well cost activity as indicated:
Costs pending the determination of proved reserves at December 31, 2014
For a period one year or less . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For a period greater than one year but less than five years . . . . . . . . . . . . . . . . . . . . . . .
For a period greater than five years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Year
Ended
December 31,
2014
(In Thousands)
$5,340
—
—
$5,340
For the Year
Ended
December 31,
2014
(In Thousands)
Costs reclassified to wells, equipment and facilities based on the determination of
proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Costs expensed due to determination of dry hole or abandonment of project . . . . . . . . .
$5,177
—
107
Standardized Measure of Discounted Future Net Cash Flows:
Future Cash Flows:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future Net Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discount to present value at a 10% annual rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Year
Ended
December 31,
2014
(In Thousands)
$920,454
312,666
20,072
587,716
282,519
Total standardized measure of discounted net cash flows . . . . . . . . . . . . . . . . . . . . . . . .
$305,197
108
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, 2014. 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 are effective 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, 2014 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, 2014. 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.
Our management’s evaluation of the effectiveness of our internal control over financial reporting does not
include the internal controls of VantaCore Partners LLC, which is included in the 2014 consolidated financial
statements of Natural Resource Partners L.P. and constituted $219.7 million and $204.5 of total and net assets,
respectively, as of December 31, 2014 and $42.1 million and $3.5 million of revenues and net income,
respectively, for the year then ended.
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, 2014, 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
109
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 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.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting,
management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did
not include the internal controls of VantaCore Partners LLC, which is included in the 2014 consolidated financial
statements of Natural Resource Partners L.P. and constituted $219.7 million and $204.5 of total and net assets,
respectively, as of December 31, 2014 and $42.1 million and $3.5 million of revenues and net income,
respectively, for the year then ended. Our audit of internal control over financial reporting of Natural Resource
Partners L.P. also did not include an evaluation of the internal control over financial reporting of VantaCore.
In our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2014, 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 sheet of Natural Resource Partners L.P. as of December 31, 2014 and
2013, and the related consolidated statements of comprehensive operations, partners’ equity and cash flows for
each of the three years in the period ended December 31, 2014 and our report dated February 27, 2015 expressed
an unqualified opinion there thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2015
Item 9B. Other Information
None.
110
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 February 27, 2015. 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, Mr. Robertson is entitled to nominate ten directors, five of whom must be independent 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.
Name
Corbin J. Robertson, Jr.
. . . . . . . . . . .
Wyatt L. Hogan(1) . . . . . . . . . . . . . . .
Craig W. Nunez . . . . . . . . . . . . . . . . .
Kevin F. Wall(2)
. . . . . . . . . . . . . . . .
Kevin J. Craig . . . . . . . . . . . . . . . . . .
Dennis F. Coker . . . . . . . . . . . . . . . . .
David M. Hartz . . . . . . . . . . . . . . . . .
Kathy H. Roberts . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . .
Gregory F. Wooten . . . . . . . . . . . . . .
Kenneth Hudson . . . . . . . . . . . . . . . . .
Robert T. Blakely . . . . . . . . . . . . . . . .
Russell D. Gordy . . . . . . . . . . . . . . . .
Donald R. Holcomb . . . . . . . . . . . . . .
Robert B. Karn III . . . . . . . . . . . . . . .
S. Reed Morian . . . . . . . . . . . . . . . . .
Richard A. Navarre . . . . . . . . . . . . . .
Corbin J. Robertson, III . . . . . . . . . . .
Stephen P. Smith . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . .
Leo A. Vecellio, Jr.
Age
67
43
53
58
46
47
41
63
40
58
60
73
64
58
73
69
54
44
53
68
Position with the General
Partner
Chairman of the Board and Chief Executive Officer
President
Chief Financial Officer and Treasurer
Chief Operating Officer
Executive Vice President, Coal
Vice President, Aggregates
Vice President, Oil and Gas
Vice President, Investor Relations
Vice President, General Counsel and Secretary
Vice President, Chief Engineer
Controller
Director
Director
Director
Director
Director
Director
Director
Director
Director
(1) Mr. Hogan will become President and Chief Operating Officer effective March 1, 2015.
(2) Mr. Wall will retire as Chief Operating Officer effective March 1, 2015.
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 partners of Western Pocahontas Properties Limited Partnership since 1986, Great Northern
Properties Limited Partnership since 1992, Quintana Minerals Corporation since 1978, and as Chairman of the
Board of Directors of New Gauley Coal Corporation since 1986. 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 World
Health and Golf Association. In 2006, Mr. Robertson was inducted into the Texas Business Hall of Fame.
Wyatt L. Hogan has served as President of GP Natural Resource Partners LLC since September 2014, and
effective March 1, 2015, Mr. Hogan will become President and Chief Operating Officer of GP Natural Resource
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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 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 OCI Wyoming LLC. Mr. Hogan also serves as a member of the
Boards of the National Mining Association and the American Coalition for Clean Coal Electricity.
Craig W. Nunez has served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC
since January 1, 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, he has been a FINRA-registered Investment Advisor Representative with
Searle & Co since July 2012 and has 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 1999 to February 2006.
Kevin F. Wall has served as Chief Operating Officer of GP Natural Resource Partners LLC since September
2014 and will retire from such position effective March 1, 2015. Mr. Wall served as Executive Vice President,
Operations of GP Natural Resource Partners LLC from December 2008 through August 2014 and as Vice
President—Engineering for GP Natural Resource Partners LLC from 2002 to 2008. Mr. Wall has also served as
Vice President—Engineering of the general partner of Western Pocahontas Properties Limited Partnership since
1998, of the general partner of Great Northern Properties Limited Partnership since 1992, and of New Gauley
Coal Corporation since 1998. Mr. Wall also represents NRP as one of its appointees to the Board of Managers of
OCI Wyoming LLC. He has performed duties in the land management, planning, project evaluation, acquisition
and engineering areas since 1981. He is a Registered Professional Engineer in West Virginia and is a member of
the American Institute of Mining, Metallurgical, and Petroleum Engineers and of the National Society of
Professional Engineers. Mr. Wall also serves on the Executive Committee for the National Council of Coal
Lessors, the Board of Directors of Leadership Tri-State and the Board of the Virginia Center for Coal and Energy
Research and is a past president of the West Virginia Society of Professional Engineers.
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 joined NRP in 2005 from CSX Transportation, where he served as Terminal Manager
for the West Virginia Coalfields. Mr. Craig has extensive experience in business development, operations,
finance and marketing within the coal industry. Mr. Craig also served as a Delegate to the West Virginia House
of Delegates having been elected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. Mr. Craig
most recently 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
is currently serving as the Chairman of the Huntington Regional Chamber of Commerce Board of Directors and
as a Director for the West Virginia Chamber of Commerce and is involved in numerous state coal associations.
Dennis F. Coker is Vice President, Aggregates of GP Natural Resource Partners LLC. Mr. Coker joined
NRP in March 2008 from Hanson Building Materials America, where he had been employed since 2002, and
most recently served as Director, Corporate Development. Mr. Coker has 19 years of experience in the mining
and materials industry, with the last 15 years focused on corporate development activity. Mr. Coker also
represents NRP as one of its appointees to the Board of Managers of OCI Wyoming LLC. Mr. Coker also serves
as Treasurer on the Executive Board of the National Stone Sand and Gravel Association.
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David M. Hartz has served as Vice President, Oil and Gas of GP Natural Resource Partners LLC since
December 2013. He served as Director, Oil and Gas from 2011 to December 2013. Prior to joining NRP,
Mr. Hartz served as Director of Scotia Waterous, the oil and gas investment banking group within Scotia Capital
from 2007 until 2011 where he was involved in oil and gas acquisition and divestiture transactions throughout the
United States. Prior to investment banking, Mr. Hartz served in a variety of technical positions as a petroleum
geologist for Texaco and Hess within several U.S. and international petroleum basins. He is a member of IPAA,
Houston Producers Forum, as well as numerous state oil and gas associations.
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 National Association of Publicly Traded Partnerships and has served on the local
board of directors of the National Investor Relations Institute and maintained professional affiliations with
various energy industry organizations. 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 practiced corporate and securities law with Vinson & Elkins L.L.P. from September 2001 to
February 2010 and from November 2011 to February 2013. Ms. Wilson served as General Counsel of Antero
Resources Corporation from March 2010 to June 2011.
Gregory F. Wooten has served as Vice President, Chief Engineer of GP Natural Resource Partners LLC
since December 2013. Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP,
Mr. Wooten served as Vice President, COO and Chief Engineer of Dingess Rum Properties, Inc., where he
managed coal, oil, gas and timber properties from 1982 until 2007. Prior to 1982, Mr. Wooten worked as a
planning and production engineer in the coal industry and is a member of the American Institute of Mining,
Metallurgical, and Petroleum Engineers.
Kenneth Hudson has served as the Controller of GP Natural Resource Partners LLC since 2002. He has
served as Controller of the general partner of Western Pocahontas Properties Limited Partnership and of New
Gauley Coal Corporation since 1988 and of the general partner of Great Northern Properties Limited Partnership
since 1992. He was also Controller of Blackhawk Mining Co., Quintana Coal Co. and other related operations
from 1985 to 1988. Prior to that time, Mr. Hudson worked in public accounting.
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 Ally Financial (formerly GMAC, Inc.), where he serves as Chairman of the Audit
Committee, and Greenhill & Co.
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
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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.
Donald R. Holcomb joined the Board of Directors of GP Natural Resource Partners LLC in October 2013.
Mr. Holcomb brings financial and coal company experience to the Board of Directors. Mr. Holcomb is currently
the Chief Executive Officer of Dickinson Fuel Company, Inc., the managing general partner of Dickinson
Properties Limited Partnership, a land company in West Virginia. He is also the owner and manager of Ikes Fork,
LLC. From 2001 to March 31, 2013, Mr. Holcomb served as Chief Financial Officer for Foresight Reserves LP
and its subsidiaries, which companies are affiliated with Christopher Cline. Mr. Holcomb also serves as trustee of
various trusts affiliated with the Cline family. Prior to joining Foresight, Mr. Holcomb held a variety of executive
management positions, including at Banner Coal & Land Company, Inc., Patriot Automotive Group, Atlantic
Mine Supply Company, Inc., and Wind River Consulting, LLC. Mr. Holcomb is a Certified Public Accountant.
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 Boards of Trustees of
numerous publicly listed closed-end funds, exchange traded funds and mutual funds of the Guggenheim family
of funds.
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 worked for Dixie Chemical Company from 1971 to 2006 and served
as its Chairman and Chief Executive Officer from 1981 to 2006. He has also served as Chairman, Chief
Executive Officer and President of DX Holding Company since 1989. He formerly served on the Board of
Directors for the Federal Reserve Bank of Dallas-Houston Branch from April 2003 until December 2008 and as a
Director of Prosperity Bancshares, Inc. from March 2005 until April 2009.
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 his retirement in 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 is an Advisory Board member for
Secure Energy, LLC. He is a member of the Hall of Fame of the College of Business, 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.
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
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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 Western Pocahontas since October 2012. 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 has been the Executive Vice President and Chief Financial Officer for NiSource, Inc. since
June 2008. Mr. Smith is also the Chief Financial Officer and Chief Accounting Officer and a Director of the
general partner of Columbia Pipeline Partners LP, which completed its initial public offering in February 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.
Corporate Governance
Board Attendance and Executive Sessions
The Board met nine times in 2014. During that period, every director attended all of the Board meetings,
with the exception of Mr. Blakely, who missed two meetings, Mr. Morian, who missed one meeting, and Corbin
J. Robertson, III, who missed one meeting. During 2014, 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 2014. 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, 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
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 2014, because we are a limited partnership as defined in Section 303A of the NYSE’s listing
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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. Mr. Blakely currently
serves on four audit committees. In accordance with the rules of the NYSE, our Board of Directors has made the
determination that Mr. Blakely’s service on four audit committees does not impair his ability to serve effectively
on our audit committee.
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 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 2014, at each of its meetings, the Committee met with the senior members of our financial
management team, our general counsel and our independent auditors. The Committee had private sessions at
certain of its meetings with our independent auditors and the senior members of our financial management team
at which candid discussions of financial management, accounting and internal control issues took place.
The Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year
ended December 31, 2014 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 AU Section 380, Communication With Audit
Committees. The Committee received and discussed with the auditors their annual written report on their
independence from the partnership and its management, which is made under Rule 3526, Communication With
Audit Committees Concerning Independence, and considered with the auditors whether the provision of non-
audit services provided by them to the partnership during 2014 was compatible with the auditors’ independence.
In performing all of these functions, the Audit Committee acts only in an oversight capacity. The 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 2014, the Committee also reviewed quarterly earnings announcements
with management and representatives of the independent auditor in advance of their issuance. In its oversight
role, the 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.
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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, 2014, 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 this Committee since 2003. Mr. Karn has served on the
Committee since 2002. Mr. Vecellio joined the committee in 2007, and Mr. Gordy joined the Committee in
December 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. 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 on
our website at www.nrplp.com and 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 2014 and except as described below, 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 2014. On
December 22, 2014, S. Reed Morian filed a Form 4 reporting the purchase of 20,000 common units in the open
market on December 11, 2014 that had not been previously reported on a timely basis.
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.
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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 2014, 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.
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, 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. Our
primary business objective is to generate cash flows at levels that can sustain long-term quarterly cash distributions
to our investors. Our executive officer compensation strategy has been designed to motivate and retain our
executive officers and to align their interests with those of our unitholders. Our objectives in determining the
compensation of our executive officers are to retain qualified people and encourage them to build the partnership in
a way that ensures the stability of the cash distributions to our unitholders and growth in our asset base. We do not
tie our compensation to achievement of specific financial targets or fixed performance criteria, but rather evaluate
the appropriate compensation on an annual basis in light of our overall business objectives.
In accordance with our objective of sustaining and increasing the quarterly distribution over the long-term,
we believe that optimal alignment between our unitholders and our executive officers is best achieved by
compensating our executive officers through sharing a percentage of distributions received by our general partner
and through distribution equivalent rights (“DERs”) tied to long-term equity-based compensation. The DERs are
contingent rights, granted in tandem with specific 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 its units during the period
such phantom unit are outstanding. Our compensation for executive officers consists of four primary
components:
•
•
•
•
base salaries;
annual cash incentive awards, including bonuses and cash payments made by our general partner based
on a percentage of the cash it receives from common units that the general partner owns;
long-term equity incentive compensation; and
perquisites and other benefits.
Mr. Robertson does not receive a salary or an annual bonus in his capacity as Chief Executive Officer.
Rather, for the reasons discussed in greater detail below, Mr. Robertson is compensated exclusively through
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long-term phantom unit grants awarded by the CNG Committee and through sharing a percentage of the
distributions received by the general partner. 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 December of each year, our CNG Committee reviews the performance of the executive officers and the
amount of time expected to be spent by each NRP officer on NRP business, and determines the salaries for each
officer for the upcoming year. All of our executive officers other than Mr. Robertson spend 93% or more of their
time on NRP matters, and NRP bears the allocated cost of their time. Mr. Robertson has historically spent
approximately 50% of his time on NRP matters.
In February of each year, the CNG Committee approves 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, we have
issued phantom units 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 typically vest four years from the
date of grant. In connection with the phantom unit awards, the CNG Committee has also granted tandem DERs,
which entitle the holders to receive upon vesting of the related phantom units an amount in cash equal to the
distributions paid on our common units during the period in which the phantom units were outstanding. The
DERs have a four-year vesting period. Through these awards, each executive officer’s interest is aligned with
those of our unitholders in sustaining and increasing our quarterly cash distributions over the long-term,
increasing the value of our common units, and maintaining a steady growth profile for NRP.
Role of Compensation Experts
The CNG Committee did not retain any consultants to evaluate compensation of officers or directors in
2014. 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.
Role of Our Executive Officers in the Compensation Process
Mr. Robertson provided recommendations to the CNG Committee in its evaluation of the 2014
compensation programs for our executive officers. Mr. Wall, our Chief Operating Officer, provided Mr. Hogan,
our President, with recommendations relating to the executive officers that are based in Huntington. Mr. Hogan
then reviewed these recommendations and provided these recommendations, along with recommendations
relating to the executive officers based in Houston, to Mr. Robertson. 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. No other named executive officer assumed an
active role in the evaluation or design of the 2014 executive officer compensation programs.
Evaluation of 2014 Performance; Components of Compensation
2014 Performance
Although we reduced our quarterly distribution in January 2014 primarily due to continued pressure on the
coal industry, we used the additional liquidity to fund a portion of the purchase prices of the acquisition of
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VantaCore Partners LLC, an operating construction aggregates producer, and the acquisition of additional non-
operated working interests in oil and gas assets in the Williston Basin of North Dakota from an affiliate of
Kaiser-Francis Oil Company. These efforts are reflective of NRP management’s desire to continue to grow and
diversify the partnership and create value for our unitholders.
During 2014, NRP’s financial performance met or exceeded the guidance issued to the public markets in
January 2014 as confirmed in August 2014. We recorded revenues and other income in 2014 of $388.9 million,
which were 8.5% higher than our revenues in 2013. In addition, although distributable cash flow was down 31%
compared to 2013, our distribution coverage ratio for 2014 was approximately 1.3x.
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 named executive officers are paid an annual base salary by Quintana Minerals
Corporation (“Quintana”) and 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 2015, at the December 2014 meeting, the CNG
Committee considered the financial performance of NRP for the nine months ended September 30, 2014 as well
as the projected financial performance of NRP for the fourth quarter of 2014 and for the year ending
December 31, 2015. The CNG Committee also considered the individual performance of each member of the
executive management team during 2014 and the changes to the management team that became effective during
the year. Based on its review, the CNG Committee determined generally to increase 2015 salaries for the
management team, with the exceptions of Mr. Dunlap, who retired as our Chief Financial Officer and Treasurer
effective January 1, 2015, and Mr. Wall, who will retire as our Chief Operating Officer effective March 1, 2015.
The amount of the increases varied among the management team members based on their expected contributions
to the company during 2015.
Annual Cash Incentive Awards
Each named executive officer, participated in two cash incentive programs in 2014, 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 2015 by the CNG Committee based on similar criteria used to evaluate the annual
base salaries. The bonuses awarded with respect to 2014 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 and Ms. Wilson were increased as a
result of NRP’s strong performance during 2014 in a difficult commodity price environment and as a result of
their contributions to the company during 2014, including with respect to the two significant acquisitions
completed during the year. The increase in Mr. Hogan’s bonus also reflects his additional responsibilities as
President. The bonuses for Mr. Dunlap, who retired as our Chief Financial Officer and Treasurer effective
January 1, 2015, and Mr. Wall, who will retire as our Chief Operating Officer effective March 1, 2015 were kept
constant at 2013 levels.
Under the second cash incentive program, our general partner has set aside 7.5% of the cash distributions it
receives on an annual basis with respect to distributions on 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 amount of the 7.5% that is allocated to each executive officer, including himself, the cash awards that our
officers receive under this plan are reviewed by the CNG Committee and taken into account when making
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determinations with respect to salaries, bonuses and long-term incentive awards. Because they are ultimately
reimbursed by the general partner and not NRP, the incentive payments made with respect to this program do not
have any impact on our financial statements or cash available for distribution to our unitholders. Since the cost of
these awards is not borne by NRP, we have not disclosed the amounts of these awards in the Summary
Compensation Table, but have included the amounts separately in a footnote to the table. With the exception of
Mr. Hogan, whose amount decreased by less than 2% over 2013, and Ms. Wilson, who was not a named
executive officer with respect to 2013, the amounts received by the named executive officers, including
Mr. Robertson, were significantly lower for 2014 as compared to 2013. The per unit distribution paid by NRP
during the calendar year ended December 31, 2014 was 37% lower than that paid in 2013, resulting in a
decreased overall amount allocated to the executive officers. The amount received by Mr. Hogan reflected his
significantly increased responsibility and contributions as President of NRP but was approximately 28% less than
the amount received by Mr. Carter, NRP’s former President and Chief Operating Officer, with respect to 2013.
The remaining portion of the cash awards under this program was allocated equally among NRP’s other
executive officers, including Mr. Robertson. We believe that these awards align the interests of our executive
officers directly with our unitholders.
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. We
consider long-term equity-based incentive compensation to be the most important element of our compensation
program for executive officers because we believe that these awards keep 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.
Consistent with this approach, we have 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.
Our CNG Committee has generally 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 have structured the phantom unit awards so that our executive officers and directors
directly benefit along with our unitholders when our unit price increases, and experience reductions in the value
of their incentive awards when our unit price declines. Similarly, because the awards are forfeited by the
executives upon termination of employment in most instances, the long-term vesting component of these awards
encourages our senior executives and employees to remain with NRP over an extended period of time, thereby
ensuring continuity in our management team. This strategy has proved effective as NRP’s senior management
team has experienced no turnover since the initial public offering.
In determining 2015 LTIP awards for NRP’s executive officers, at the February 2015 meeting, the CNG
Committee considered the financial performance of NRP for the year ended December 31, 2014 as well as the
projected financial performance of NRP for the year ending December 31, 2015. When determining the 2015
LTIP awards, the CNG Committee’s goal was to incentivize the management team during this difficult
commodity price cycle and foster the retention of such officers. Mr. Robertson’s 2015 award was increased
consistent with the level of increases in awards to him in prior years. Mr. Dunlap’s 2015 award was lower than
the previous year due to his retirement from NRP effective January 1, 2015 and the expectation that he will
allocate approximately 50% of his time to NRP during 2015. Mr. Hogan’s 2015 award was increased relative to
2014 in order to reflect his increased responsibilities as President of NRP. Mr. Wall did not receive a 2015 award
due to his retirement from NRP effective March 1, 2015. However, the CNG Committee has determined that all
of Mr. Wall’s outstanding LTIP awards will be vested upon his retirement from NRP effective March 1, 2015.
Ms. Wilson’s 2015 award was increased to a level consistent with that of NRP’s other executive officers.
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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 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. The payments made to Messrs. Dunlap, Hogan, Wall and Carter under the defined contribution plan
exceeded $10,000 in each of 2012, 2013 and 2014, but did not exceed $25,000 for any individual in any year.
The payment made to Ms. Wilson, who was not a named executive officer in 2012 or 2013, under the defined
contribution plan in 2014 exceeded $10,000 but did not exceed $25,000. None of NRP, Quintana or Western
Pocahontas maintains a pension plan or a defined benefit retirement plan. As noted in the Summary
Compensation Table, in 2012, 2013 and 2014 we also reimbursed Quintana and Western Pocahontas for car
allowances provided to Messrs. Dunlap, Wall and Carter.
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, 2014, our named executive officers held 272,425 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
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 2012, 2013 or 2014. 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
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foregoing sentence, the CNG Committee recommended to the board of directors that the Compensation
Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2014.
Robert T. Blakely, Chairman
Russell D. Gordy
Robert B. Karn III
Leo A. Vecellio, Jr.
Summary Compensation Table
The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation
expense in 2012, 2013 and 2014 based on time allocated by each individual to Natural Resource Partners. In
2014, Messrs. Robertson, Dunlap, Hogan and Wall and Ms. Wilson spent approximately 50%, 96%, 100%, 95%
and 93%, respectively, of their time on NRP matters. Mr. Carter retired as President and Chief Operating Officer
effective September 1, 2014. Prior to that, Mr. Carter spent approximately 97% of this time on NRP matters.
Phantom unit awards in the table below represent all amounts paid to the named executive officers in 2014 with
respect to the vesting of such awards, as NRP bears 100% of the costs of all awards under the LTIP.
Summary Compensation Table
Name and Principal Position
Corbin J. Robertson, Jr. . . . . . . . . . . . . . . . . . .
Chairman and CEO
Dwight L. Dunlap(1) . . . . . . . . . . . . . . . . . . . .
Chief Financial Officer and Treasurer
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . .
President
Kevin F. Wall
. . . . . . . . . . . . . . . . . . . . . . . . .
Chief Operating Officer
Kathryn S. Wilson(2)
. . . . . . . . . . . . . . . . . . .
Vice President, General Counsel and
Secretary
Year
Salary
($)
Bonus
($)
—
—
—
327,343
328,193
325,189
377,654
344,970
328,337
215,759
205,485
205,485
—
2014
—
2013
—
2012
126,900
2014
126,900
2013
141,000
2012
225,000
2014
126,900
2013
141,000
2012
126,900
2014
126,900
2013
2012
141,000
2014 291,375 100,000
Phantom
Unit
Awards(4)
($)
All Other
Compensation(5)
($)
595,728
712,000
830,400
186,165
222,500
259,500
186,165
222,500
259,500
186,165
222,500
259,500
121,007
—
—
—
39,056
38,537
37,577
33,336
31,358
30,988
35,099
33,781
33,781
30,869
Total
($)
595,728
712,000
830,400
679,464
716,130
763,266
822,155
725,728
759,825
563,923
588,666
639,766
543,251
Nick Carter(3) . . . . . . . . . . . . . . . . . . . . . . . . .
Former President and Chief Operating
Officer
2014
2013
2012
252,200
378,300
378,300
133,000
199,260
221,400
297,864
356,000
415,200
99,458(6)
40,473
39,851
782,522
974,033
1,054,751
(1) Mr. Dunlap retired as Chief Financial Officer and Treasurer effective January 1, 2015.
(2) Ms. Wilson was not a named executive officer for purposes of this Summary Compensation Table during
2013 or 2012.
(3) Mr. Carter retired as President and Chief Operating Officer effective September 1, 2014. Mr. Carter
remained employed by Western Pocahontas Properties Limited Partnership from September 1, 2014 through
December 31, 2014 and provided consulting services to Natural Resource Partners L.P. during that time. He
continued to receive his 2014 salary and employee benefits through December 31, 2014. One-half of the
expenses related to Mr. Carter’s salary and employee benefits for the last four months of 2014 was borne by
Natural Resource Partners L.P.
(4) Amounts represent the grant date fair value of phantom unit awards determined in accordance with
Accounting Standards Codification Topic 718. For information regarding the assumptions used in
calculating these amounts for 2014, see Note 16 to the audited consolidated financial statements included
elsewhere in this Annual Report on Form 10-K.
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(5)
Includes portions of automobile allowance, 401(k) matching and retirement contributions allocated to
Natural Resource Partners by Quintana and Western Pocahontas. The table does not include any cash
compensation paid by the general partner to each named executive officer. The general partner may
distribute up to 7.5% of any cash it receives with respect to the common units that it received in connection
with the elimination of the incentive distribution rights. We do not reimburse the general partner for any of
these payments, and the payments are not an expense of NRP. The table below shows the amounts paid by
the general partner that are not reimbursed by NRP:
Compensation Received from General Partner
and Not Reimbursed by NRP
Individual
Corbin J. Robertson, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year
2014
2013
2012
2014
2013
2012
2014
2013
2012
2014
2013
2012
2014
2014
2013
2012
$
180,000
456,000
456,000
180,000
391,000
391,000
384,000
391,000
391,000
180,000
391,000
391,000
180,000
—
536,000
536,000
(6)
Includes $65,000 salary and $7,061 for 401K match, retirement contribution and car allowance in other
compensation received by Mr. Carter for the months of September through December 2014. These amounts
represent 50% of the total salary and other compensation received by Mr. Carter during that period.
Grants of Plan-Based Awards in 2014
Named Executive Officer
Corbin J. Robertson, Jr. . . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter
Grant Date
2/12/2014
2/12/2014
2/12/2014
2/12/2014
2/12/2014
2/12/2014
Number of
Phantom Units(1)
(#)
Grant Date
Fair Value of
Unit Awards(2)
($)
33,600
10,500
10,500
10,500
6,825
16,800
595,728
186,165
186,165
186,165
121,007
297,864
(1) The phantom units were granted in February 2014 and will vest in February 2018.
(2) Amounts represent the grant date fair value of phantom unit awards determined in accordance with
Accounting Standards Codification Topic 718.
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.
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Subject to the rules of the exchange upon which the common units are listed at the time, the board of
directors 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 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 NRP, our 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 CNG Committee provides otherwise.
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. The CNG Committee regularly
makes awards of phantom units on an annual basis in February.
Outstanding Awards at December 31, 2014
The table below shows the total number of outstanding phantom units held by each named executive officer
at December 31, 2014. The phantom units shown below have been awarded over the last four years, with a
portion of the phantom units vesting in February in each of 2015, 2016, 2017 and 2018.
Named Executive Officer
Number of
Phantom Units That
Have Not Vested
(#)
Market Value
of Phantom Units That
Have Not Vested(1)
($)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corbin J. Robertson, Jr.
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
130,600(2)
39,500(3)
39,500(3)
39,500(3)
23,325(4)
—
1,754,120
526,270
526,270
526,270
273,247
—
(1) Based on a unit price of $9.25, the closing price for the common units on December 31, 2014. The value
also includes the value of the accrued DERs as of December 31, 2014.
(2)
(3)
(4)
Includes 33,000 phantom units vested on February 10, 2015, 32,000 phantom units vesting on February 14,
2016, 32,000 phantom units vesting on February 13, 2017 and 33,600 phantom units vesting on
February 12, 2018.
Includes 9,000 phantom units vested on February 10, 2015, 10,000 phantom units vesting on February 14,
2016, 10,000 phantom units vesting on February 13, 2017 and 10,500 phantom units vesting on
February 12, 2018.
Includes 4,500 phantom units vested on February 10, 2015, 5,500 phantom units vesting on February 14,
2016, 6,500 phantom units vesting on February 13, 2017 and 6,825 phantom units vesting on February 12,
2018. Phantom units vested in 2015 and phantom units vesting in 2016 and 2017 include accrued DERs
from February 12, 2013, the date of the grant of these units to Ms. Wilson.
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Phantom Units Vested in 2014
The table below shows the phantom units that vested with respect to each named executive officer in 2014,
along with the value realized by each individual.
Named Executive Officer
Number of
Phantom Units That
Vested
(#)
Value Realized on
Vesting
($)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corbin J. Robertson, Jr.
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33,000
8,000
8,000
8,000
3,500
77,800
803,880
194,880
194,880
194,880
62,335(1)
1,592,214
(1)
Includes accrued DERs from February 12, 2013, the date of the grant of these units to Ms. Wilson.
(2)
Includes the phantom units and amount paid to Mr. Carter upon the vesting of all of his phantom units upon
his retirement effective September 1, 2014 pursuant to the terms of Mr. Carter’s Continued Employment
and Separation Agreement. In accordance with the terms of the phantom units, Mr. Carter received for each
phantom unit an amount in cash equal to the average closing price of NRP’s common units for the 20
trading days immediately preceding the vesting date, together with associated DERs. See “—Potential
Payments upon Termination or Change in Control.”
Potential Payments upon Termination or Change in Control
Upon the occurrence of a change in control of NRP, our general partner or GP Natural Resource Partners
LLC, 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 the outstanding equity-based awards at December 31,
2014, based on the 20-day average of the common units of $9.78 on December 31, 2014 and includes amounts
for accrued DERs.
Named Executive Officer
Corbin J. Robertson, Jr.
. . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of
Phantom
Units
That Have
Not Vested
(#)
130,600
39,500
39,500
39,500
23,325
—
Potential
Post-Employment
Payments
Required Upon
Change in
Control
($)
Potential
Cash Payments
Required Upon
Change in
Control
($)
—
—
—
—
—
—
1,823,142
547,146
547,146
547,146(1)
285,575(2)
—
(1) The CNG Committee has determined that all of Mr. Wall’s phantom units will vest upon his retirement
effective March 1, 2015. In accordance with the terms of the phantom units, Mr. Wall will receive for each
phantom unit an amount in cash equal to the average closing price of NRP’s common units for the 20
trading days immediately preceding the vesting date, together with associated DERs.
(2) Phantom units vested in 2015 and phantom units vesting in 2016 and 2017 include accrued DERs from
February 12, 2013, the date of the grant of these units to Ms. Wilson.
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
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of their employment. However, in connection with Mr. Carter’s retirement on September 1, 2014, Mr. Carter,
NRP and Western Pocahontas entered into a Continued Employment and Separation Agreement. Pursuant to that
agreement, Mr. Carter continued to receive his salary and benefits through December 2014 (of which $72,061, or
50%, was borne by NRP), a bonus payment of $133,000 on December 31, 2014 (all of which was borne by
NRP), and a payment of $1,251,174 upon the accelerated vesting of all of his 63,800 outstanding phantom units
on September 1, 2014.
Directors’ Compensation for the Year Ended December 31, 2014
The table below shows the directors’ compensation for the year ended December 31, 2014. As with our
named executive officers, we do not grant any options or restricted units to our directors.
Name of Director
Fees Earned
or Paid in
Cash
($)
Phantom
Unit
Awards(1)(2)
($)
Robert Blakely . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Russell Gordy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Donald Holcomb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert Karn III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S. Reed Morian . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Richard Navarre . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corbin J. Robertson, III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stephen Smith . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leo A. Vecellio, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
85,000
65,000
60,000
85,000
60,000
65,000
60,000
80,000
65,000
84,651
16,710
16,710
84,651
84,651
16,710
59,978
84,651
84,651
Total
($)
169,651
81,710
76,710
169,651
144,651
81,710
119,978
164,651
149,651
(1) Amounts represent the grant date fair value of unit awards determined in accordance with FASB stock
compensation authoritative guidance.
(2) As of December 31, 2014, each director held 14,865 phantom units, of which 3,580 vested on February 10,
2015, 3,700 will vest on February 14, 2016, 3,700 will vest on February 13, 2017 and 3,885 will vest on
February 12, 2018.
In 2014, 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.
2015 Long-Term Incentive Awards
In February 2015, the CNG Committee awarded 36,000 phantom units to Mr. Robertson, 4,000 phantom
units to Mr. Dunlap, 18,000 phantom units to Mr. Hogan, and 9,500 phantom units to Ms. Wilson. The phantom
units included tandem DERs, pursuant to which the phantom units will accrue the quarterly distributions paid by
NRP on its common units. NRP will pay the amounts accrued under the DERs upon the vesting of the phantom
units in February 2019. The CNG Committee also approved an award of 4,100 phantom units, including tandem
DERs, to each of the members of the Board of Directors. These phantom units will vest in February 2019.
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2014, Messrs. Blakely, Gordy, Karn and Vecellio served on the CNG
Committee. None of Messrs. Blakely, Carmichael, 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 of Directors or CNG Committee.
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Item 12.
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth, as of February 27, 2015, 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.
Name of Beneficial Owner
Corbin J. Robertson, Jr.(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Western Pocahontas Properties(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Craig W. Nunez . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin J. Craig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dennis F. Coker . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
David M. Hartz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kenneth Hudson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathy H. Roberts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gregory F. Wooten . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert T. Blakely . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Russell D. Gordy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Donald R. Holcomb(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert B. Karn III(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Richard A. Navarre . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S. Reed Morian(8)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corbin J. Robertson III(9) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stephen P. Smith . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leo A. Vecellio, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Directors and Officers as a Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common
Units
24,346,308
17,279,860
12,500
—
4,000
18,000
4,500
1,140
8,000
20,000
—
—
22,500
70,000
5,469,950
5,634
—
6,161,588
1,727,892
3,552
20,000
37,895,563
Percentage of
Common
Units(1)
19.9%
14.1%
*
—
*
*
*
*
*
*
—
—
*
*
4.5%
*
—
5.0%
1.4%
*
*
31.0%
*
Less than one percent.
(1) Percentages based upon 122,299,825 common units issued and outstanding. Unless otherwise noted,
beneficial ownership is less than 1%.
(2) Mr. Robertson may be deemed to beneficially own the 17,279,860 common units owned by Western
Pocahontas Properties Limited Partnership, 5,627,120 common units held by Western Bridgeport, Inc.,
110,206 common units held by Western Pocahontas Corporation and 56 common units held by QMP Inc.
Also included are 31,540 common units held by Barbara Robertson, Mr. Robertson’s spouse.
Mr. Robertson’s address is 601 Jefferson Street, Suite 3600, Houston, Texas 77002. The 5,627,120 units
held by Western Bridgeport are pledged as collateral for a loan.
(3) These common units may be deemed to be beneficially owned by Mr. Robertson. The address of Western
Pocahontas Properties Limited Partnership is 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
(4) Of these common units, 500 common units are owned by the Anna Margaret Hogan 2002 Trust, 500
common units are owned by the Alice Elizabeth Hogan 2002 Trust, and 500 common units are held by the
Ellen Catlett Hogan 2005 Trust. Mr. Hogan is a trustee of each of these trusts.
128
(5)
(6)
Includes 500 common units held by Mr. Wall’s daughter. Mr. Wall disclaims beneficial ownership of these
securities.
Includes 5,349,816 common units held by Cline Trust Company LLC. Mr. Holcomb is a manager of Cline
Trust Company and may be deemed to have voting or investment power over the common units held of
record by Cline Trust Company. The members of Cline Trust Company are for trusts for the benefit of
Christopher Cline, and Mr. Holcomb serves as trustee of each of those trusts. Mr. Holcomb disclaims
beneficial ownership of the common units held by Cline Trust Company.
(7)
Includes 317 common units held by each of two trusts for the benefit of Mr. Karn’s grandchildren. Mr. Karn
is the trustee of each of these trusts for his grandchildren, but disclaims beneficial ownership of these
securities.
(8) Mr. Morian may be deemed to beneficially own 3,448,624 common units owned by Shadder Investments
and 600,972 common units held by Mocol Properties. The 3,448,624 units owned by Shadder Investments
are pledged as collateral for a loan.
(9) Mr. Robertson may be deemed to beneficially own 97,828 common units held CIII Capital Management,
LLC, 100,000 common units held by BHJ Investments, 50,461 common units held by The Corbin James
Robertson III 2009 Family Trust and 387 common units held by his spouse, Brooke Robertson. The address
for CIII Capital Management, LLC is 601 Jefferson, Suite 3600, Houston, TX 77002, the address for BHJ
Investments is 601 Jefferson, Suite 3600, Houston, TX 77002 and the address for The Corbin James
Robertson III 2009 Family Trust is 601 Jefferson, Suite 3600, Houston, TX 77002. The following common
units are pledged as collateral for loans: 295,413 common units owned directly by Mr. Robertson and
31,000 of the units held by CIII Capital Management, LLC.
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.
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• the asset or group of related assets of the restricted business have a fair market value of $10 million or
less; provided that if the fair market value of the assets of the restricted business subsequently exceeds $10
million, the GP affiliate must offer the restricted business to us under the offer procedures described
below.
• the asset or group of related assets of the restricted business have a fair market value of more than $10
million and the general partner (with the approval of the conflicts committee) has elected not to cause us
to purchase these assets under the procedures described below.
• its ownership in the restricted business consists solely of a non-controlling equity interest.
For purposes of this paragraph, “fair market value” means the fair market value as determined in good faith
by the relevant GP affiliate.
The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged
in by the WPP Group, other than those engaged in by the WPP Group at closing of our initial public offering,
may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a
restricted business purchased by the WPP Group will be determined based on the fair market value of the entity
as a whole, without regard for any lesser ownership interest to be acquired.
If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business
with a fair market value in excess of $10 million and the restricted business constitutes greater than 50% of the
value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase the
restricted business. If the WPP Group desires to acquire a restricted business or an entity that engages in a
restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the
value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer
us the opportunity to purchase the restricted business within six months of acquisition. For purposes of this
paragraph, “restricted business” excludes a general partner interest or managing member interest, which is
addressed in a separate restriction summarized below. For purposes of this paragraph only, “fair market value”
means the fair market value as determined in good 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.
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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.
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 recent acquisitions and revenues that we have derived from the Cline relationship,
see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—
Significant Acquisitions” and “—Transactions with Cline Affiliates.”
Mr. Holcomb, who was appointed to the Board in October 2013, 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 approximately 5.35 million of our
common units and $20 million in principal amount of our 9.125% Senior Notes due 2018. 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 Donald R. Holcomb 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.
131
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private
equity funds focused on investments in the energy business. NRP’s Board of Directors has adopted a formal
conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by
Quintana Capital. The basic tenets of the policy are set forth below.
NRP’s business strategy has historically focused on:
• The ownership of natural resource properties in North America, including, but not limited to coal,
aggregates and industrial minerals, and oil and gas. NRP leases these properties to mining or operating
companies that mine or produce the resources and pay NRP a royalty.
• The ownership and operation of transportation, storage and related logistics activities related to extracted
hard minerals.
The businesses and investments described in this paragraph are referred to as the “NRP Businesses.”
NRP’s acquisition strategy also includes:
• The ownership of non-operating working interests in oil and gas properties.
• The ownership of non-controlling equity interests in companies involved in natural resource development
and extraction.
• The operation of construction aggregates mining and production businesses.
The businesses and investments described in this paragraph are referred to as the “Shared Businesses.”
NRP’s business strategy does not, and is not expected to, include:
• The ownership of equity interests in companies involved in the mining or extraction of coal.
• Investments that do not generate “qualifying income” for a publicly traded partnership under U.S. tax
regulations.
• Investments outside of North America.
• Midstream or refining businesses that do not involve hard extracted minerals, including the gathering,
processing, fractionation, refining, storage or transportation of oil, natural gas or natural gas liquids.
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.
132
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 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Related Party Transactions—Quintana Capital
Group GP, Ltd.”
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;
133
• 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;
• the issuance of additional common units; and
• the creation, reduction or increase of reserves in any quarter.
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general
partner to the unitholders, including borrowings that have the purpose or effect of enabling our general partner to
receive distributions.
For example, in the event we have not generated sufficient cash from our operations to pay the quarterly
distribution on our common units, our partnership agreement permits us to borrow funds which may enable us to
make this distribution on all outstanding common units.
The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner
and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries.
We do not have any officers or employees and rely solely on officers and employees of GP Natural Resource
Partners LLC and its affiliates.
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.
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We reimburse our general partner and its affiliates for expenses.
We reimburse our general partner and its affiliates for costs incurred in managing and operating us,
including costs incurred in rendering corporate staff and support services to us. The partnership agreement
provides that our general partner determines the expenses that are allocable to us in any reasonable manner
determined by our general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has
recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides
that any action taken by our general partner to limit its liability or our liability is not a breach of our general
partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on
liability.
Common unitholders have no right to enforce obligations of our general partner and its affiliates under
agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not
grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and
its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the
result of arm’s-length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered
to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also
enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership
agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our
general partner and its affiliates, on the other, are the result of arm’s-length negotiations.
All of these transactions entered into after our initial public offerings are on terms that are fair and
reasonable to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our
general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with
that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
We may not choose to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent auditors and others who have performed services for us in the past were retained
by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates
and us. Attorneys, independent auditors and others who perform services for us are selected by our general
partner or the conflicts committee and may also perform services for our general partner and its affiliates. We
may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest
arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on
the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has
not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
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.
The Conflicts Committee Charter is available on our website at www.nrplp.com and is available in print
upon request.
135
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, 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,
2014, 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 2014 and 2013. 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:
2014
2013
Audit Fees(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-Related Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax Fees(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All Other Fees(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,056,542
—
738,626
1,910
$753,502
—
654,776
1,995
(1) Audit fees include fees associated with the annual integrated audit of our consolidated financial statements
and internal controls over financial reporting, separate audits of subsidiaries and reviews of our quarterly
financial statement for inclusion in our Form 10-Q and comfort letters; consents; work related to
acquisitions; assistance with and review of documents filed with the SEC.
(2) Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return
preparation and filing of Schedules K-1.
(3) All other fees include the subscription to EY Online research tool.
Audit and Non-Audit Services Pre-Approval Policy
I. Statement of Principles
Under the Sarbanes-Oxley Act of 2002 (the “Act”), the Audit Committee of the Board of Directors is
responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of
this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by
the independent auditor in order to assure that they do not impair the auditor’s independence from the
Partnership. To implement these provisions of the Act, the SEC has issued rules specifying the types of services
that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of
the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of
Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the “Policy”), which sets forth the
procedures and the conditions pursuant to which services proposed to be performed by the independent auditor
may be pre-approved.
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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.
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
137
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.
VII. Procedures
All requests or applications for services to be provided by the independent auditor that do not require
specific approval by the Audit Committee will be submitted to the Chief Financial Officer and must include a
detailed description of the services to be rendered. The Chief Financial Officer will determine whether such
services are included within the list of services that have received the general pre-approval of the Audit
Committee. The Audit Committee will be informed on a timely basis of any such services rendered by the
independent auditor.
Requests or applications to provide services that require specific approval by the Audit Committee will be
submitted to the Audit Committee by both the independent auditor and the Chief Financial Officer, and must
include a joint statement as to whether, in their view, the request or application is consistent with the SEC’s rules
on auditor independence.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
(a)(1) and (2) Financial Statements and Schedules
See “Item 8. Financial Statements and Supplementary Data.”
(a)(3) OCI Wyoming LLC Financial Statements. The financial statements of OCI Wyoming LLC
required pursuant to Rule 3-09 of Regulation S-X are included in this filing as Exhibit 99.3.
(a)(4) Exhibits
Exhibit
Number
Description
2.1
2.2
2.3
3.1
— Purchase Agreement, dated as of January 23, 2013, by and among Anadarko Holding Company, Big
Island Trona Company, NRP Trona LLC and NRP (Operating) LLC (incorporated by reference to
Exhibit 2.1 to Current Report on Form 8-K filed on January 25, 2013).
— 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).
— 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).
3.2
— 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).
3.3
— Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource
Partners LLC, dated as of October 31, 2013 (incorporated by reference to Exhibit 3.1 to Current
Report on Form 8-K filed on October 31, 2013).
3.4
3.5
— 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).
4.1
— 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).
4.2
4.3
— 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).
139
Exhibit
Number
Description
4.4
— 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).
4.5
— 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).
4.6
4.7
— 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).
4.8
— 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).
4.9
— Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed
June 23, 2003).
4.10 — Form of Series B Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed
June 23, 2003).
4.11 — Form of Series C Note (incorporated by reference to Exhibit 4.4 to Current Report on Form 8-K filed
June 23, 2003).
4.12 — Form of Series D Note (incorporated by reference to Exhibit 4.12 to Annual Report on Form 10-K
filed February 28, 2007).
4.13 — Form of Series E Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed
March 29, 2007).
4.14 — Form of Series F Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q
filed May 7, 2009).
4.15 — Form of Series G Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q
filed May 7, 2009).
4.16 — Form of Series H Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q
filed May 5, 2011).
4.17 — Form of Series I Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q
filed May 5, 2011).
4.18 — Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed
on June 15, 2011).
4.19 — Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed
on October 3, 2011).
4.20 — 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).
4.21 — Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of Natural
Resource Partners L.P., dated March 6, 2012 (incorporated by reference to Exhibit 4.1 to Quarterly
Report on Form 10-Q filed on August 7, 2012).
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Exhibit
Number
Description
4.22 — 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).
4.23 — Form of 9.125% Senior Notes due 2018 (contained in Exhibit 1 to Exhibit 4.22).
4.24 — 9.125% Senior Note due 2018 in $20,000,000 aggregate principal amount issued by Natural
Resource Partners L.P. and NRP Finance Corporation to Cline Trust Company, LLC, dated
October 17, 2014 (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed on
October 20, 2014).
4.25 — Registration Rights Agreement, dated October 17, 2014, by and among Natural Resource Partners
L.P., NRP Finance Corporation and Wells Fargo Securities, LLC, as representative of the several
initial purchasers (incorporated by reference to Exhibit 4.4 to Current Report on Form 8-K filed on
October 20, 2014).
10.1 — Second Amended and Restated Credit Agreement, dated as of August 10, 2011 (incorporated by
reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 11, 2011).
10.2 — First Amendment to the Second Amended and Restated Credit Agreement, dated as of January 23,
2013 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed on January 25,
2013).
10.3 — Second Amendment to the Second Amended and Restated Credit Agreement, dated as of June 7,
2013 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 10,
2013).
10.4 — 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).
10.5+ — 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).
10.6+ — 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).
10.7+ — 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).
10.8 — 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).
10.9 — 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).
10.10 — 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).
141
Exhibit
Number
Description
10.11 — 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).
10.12 — Common Unit Purchase Agreement, dated January 23, 2013, 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 January 25, 2013).
10.13 — Term Loan Agreement, dated as of January 23, 2013, by and among Natural Resource Partners, L.P.,
Citibank, N.A., as administrative agent, Citigroup Global Markets, Inc., Wells Fargo Securities, LLC
and Compass Bank, as joint lead arrangers and joint bookrunners and Wells Fargo Bank, National
Association and Compass Bank, as co-syndication agents (incorporated by reference to Exhibit 10.2
to Current Report on Form 8-K filed on January 25, 2013).
10.14 — First Amendment to Term Loan Agreement, dated as of June 7, 2013 (incorporated by reference to
Exhibit 10.2 to Current Report on Form 8-K filed on June 10, 2013).
10.15 — Limited Liability Company Agreement of OCI Wyoming LLC, dated June 30, 2014 (incorporated by
reference to Exhibit 10.1 to Current Report on Form 8-K filed by OCI Resources LP on July 2,
2014).
10.16 — 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).
10.17 — 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).
10.18
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).
10.19 — Purchase Agreement dated October 9, 2014 by and among Natural Resource Partners L.P., NRP
Finance Corporation and Wells Fargo Securities, LLC (as the representative of the several initial
purchasers) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on
October 10, 2014).
10.20 — Equity Distribution Agreement dated November 12, 2013 by and among the Partnership, NRP (GP)
LP, GP Natural Resource Partners LLC, and Citigroup Global Markets Inc. BB&T Capital Markets, a
division of BB&T Securities, LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as
Managers (incorporated by reference to Exhibit 1.1 to Current Report on Form 8-K filed on
November 12, 2013).
10.21+ — Continued Employment and Separation Agreement dated effective as of September 1, 2014, by and
among Natural Resource Partners L.P., Western Pocahontas Properties Limited Partnership and Nick
Carter (incorporated by reference to Exhibit 10.3 filed on November 7, 2014).
21.1* — List of subsidiaries of Natural Resource Partners L.P.
23.1* — Consent of Ernst & Young LLP.
142
Exhibit
Number
Description
23.2* — Consent of Deloitte & Touche LLP.
23.3* — Consent of Netherland, Sewell & Associates, Inc.
31.1* — Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
31.2* — Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1* — Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2* — Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
95.1* — Mine Safety Disclosure.
99.1 — Description of certain provisions of the Fourth Amended and Restated Agreement of Limited
Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 99.1 to Current
Report on Form 8-K filed on September 21, 2010).
99.2* — Report of Netherland, Sewell & Associates, Inc.
99.3* — Financial Statements of OCI Wyoming LLC as of and for the years ended December 31, 2013 and
2014.
101* — The following financial information from the Annual Report on Form 10-K of Natural Resource
Partners L.P. for the year ended December 31, 2014, formatted in XBRL (eXtensible Business
Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of
Comprehensive Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated
Financial Statements, tagged as blocks of text.
*
Submitted herewith
** Management compensatory plan or arrangement
143
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
NATURAL RESOURCE PARTNERS L.P.
By: NRP (GP) LP, its general partner
By: GP NATURAL RESOURCE
PARTNERS LLC, its general partner
Date: February 27, 2015
Date: February 27, 2015
Date: February 27, 2015
By:
/s/ CORBIN J. ROBERTSON, JR.
Corbin J. Robertson, Jr.
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
By:
By:
/s/ CRAIG W. NUNEZ
Craig W. Nunez
Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/s/ KENNETH HUDSON
Kenneth Hudson
Controller
(Principal Accounting Officer)
144
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by
the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: February 27, 2015
Date: February 27, 2015
Date: February 27, 2015
Date: February 27, 2015
Date: February 27, 2015
Date: February 27, 2015
/s/ ROBERT T. BLAKELY
Robert T. Blakely
Director
/s/ RUSSELL D. GORDY
Russell D. Gordy
Director
/s/ DONALD R. HOLCOMB
Donald R. Holcomb
Director
/s/ ROBERT B. KARN III
Robert B. Karn III
Director
/s/
S. REED MORIAN
S. Reed Morian
Director
/s/ RICHARD A. NAVARRE
Richard A. Navarre
Director
145
Date: February 27, 2015
Date: February 27, 2015
Date: February 27, 2015
/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
146
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
BRP LLC (51% interest)
CoVal Leasing Company, LLC (51% interest)
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statements (Form S-3 No. 333-180907, Form S-3 No. 333-183314
and Form S-3 No. 333-187883) of Natural Resource Partners L.P. and in the related Prospectuses of our reports dated February 27,
2015, 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, 2014.
Exhibit 23.1
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2015
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statements on Form S-3 (Nos. 333-180907, 333-183314, and 333-
187883) of Natural Resource Partners L.P., of our report dated February 26, 2015, relating to the financial statements of OCI
Wyoming LLC for the year ended December 31, 2014, appearing in the Annual Report on Form 10-K of Natural Resource Partners
L.P. for the year ended December 31, 2014.
Exhibit 23.2
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
February 26, 2015
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the use by Natural Resource Partners L.P. (the “Company”) of our name and to the inclusion of information
taken from our report dated January 21, 2015 included in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2014, filed with the U.S. Securities and Exchange Commission on or about February 27, 2015, as well as to the
incorporation by reference thereof into the Company’s Registration Statements on Form S-3 (Nos. 333-180907, 333-183314 and 333-
187883).
Exhibit 23.3
NETHERLAND, SEWELL & ASSOCIATES,
INC.
By: /s/ Danny D. Simmons
Danny D. Simmons, P.E.
President and Chief Operating Officer
Houston, Texas
February 27, 2015
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
I, Corbin J. Robertson, Jr., certify that:
1)
I have reviewed this report on Form 10-K of Natural Resource Partners L.P.
Exhibit 31.1
2) 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;
3) 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;
4)
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.
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;
b. 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;
c.
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
d. 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.
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
b. 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.
Date: February 27, 2015
By:
/s/ Corbin J. Robertson, Jr.
Corbin J. Robertson, Jr.
Chief Executive Officer
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
I, Craig W. Nunez, certify that:
1)
I have reviewed this report on Form 10-K of Natural Resource Partners L.P.
Exhibit 31.2
2) 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;
3) 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;
4)
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.
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;
b. 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;
c.
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
d. 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.
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
b. 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.
Date: February 27, 2015
By:
/s/ Craig W. Nunez
Craig W. Nunez
Chief Financial Officer and Treasurer
CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
Exhibit 32.1
In connection with the accompanying report on Form 10-K for the year ended December 31, 2014 filed with the Securities and
Exchange Commission on the date hereof (the “Report”), I, Corbin J. Robertson, Jr., Chief Executive Officer and Chairman of the
Board 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.
/s/ Corbin J. Robertson, Jr.
Name: Corbin J. Robertson, Jr.
Date: February 27, 2015
CERTIFICATION OF
CHIEF FINANCIAL OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
Exhibit 32.2
In connection with the accompanying report on Form 10-K for the year ended December 31, 2014 filed with the Securities and
Exchange Commission on the date hereof (the “Report”), I, Craig W. Nunez, Chief Financial Officer and Treasurer 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:
3.
4.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
/s/ Craig W. Nunez
Name: Craig W. Nunez
Date: February 27, 2015
MINE SAFETY DISCLOSURE
Exhibit 95.1
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 year ended December 31, 2014.
Mine Name / MSHA
Identification Number
Winn Materials, LLC/40-03094
Laurel Aggregates of Delaware,
LLC/36-08891
Southern Aggregates, LLC-Plant
11/16-01537
Southern Aggregates, LLC-Plant
1/16-01388
Southern Aggregates, LLC-Plant
7/16-01519
Southern Aggregates, LLC-Plant
6/16-00336
Southern Aggregates, LLC-Plant
9/16-01536
Southern Aggregates, LLC-Plant
12/16-01546
Section 104
S&S
Citations(1)
2
5
1
2
4
1
1
0
Section
104(b)
Orders (2)
Section
104(d)
Citations and
Orders (3)
Section
110(b)(2)
Violations (4)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Section
107(a)
Orders (5)
0
0
0
0
0
0
0
0
Total Dollar
Value of MSHA
Assessments
Proposed (6)
$
$
$
$
$
$
$
$
3,407(7)
1,489(8)
150
617
1,143
524
634
0
(1) Mine Act section 104 S&S citations shown above are for alleged violations of mandatory health or safety standards that could
significantly and substantially contribute to a mine health and safety hazard. It should be noted that, for purposes of this table,
S&S citations that are included in another column, such as Section 104(d) citations, are not also included as Section 104 S&S
citations in this column.
(2) Mine Act section 104(b) orders are for alleged failures to totally abate a citation within the time period specified in the citation.
(3) Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e., aggravated conduct constituting more
than ordinary negligence) to comply with mandatory health or safety standards.
(4) Mine Act section 110(b)(2) violations are for an alleged “flagrant” failure (i.e., reckless or repeated) to make reasonable efforts
to eliminate a known violation of a mandatory safety or health standard that substantially and proximately caused, or reasonably
could have been expected to cause, death or serious bodily injury.
(5) Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or
serious physical harm before such condition or practice can be abated and result in orders of immediate withdrawal from the
area of the mine affected by the condition.
(6) Amounts shown include assessments proposed by MSHA during the twelve months ended December 31, 2014 on all citations
and orders, including those citations and orders that are not required to be included within the above chart.
(7) Excludes penalties for three non-S&S citations issued in 2014 that were not assessed until 2015.
(8) Excludes penalties for eight citations (two of which were S&S) issued in 2014 that were not assessed until 2015.
Mine Name / MSHA
Identification Number
Winn Materials, LLC/40-
03094
Laurel Aggregates of
Delaware, LLC/36-08891
Southern Aggregates, LLC-
Plant 11/16-01537
Southern Aggregates, LLC-
Plant 1/16-01388
Southern Aggregates, LLC-
Plant 7/16-01519
Southern Aggregates, LLC-
Plant 6/16-00336
Southern Aggregates, LLC-
Plant 9/16-01536
Southern Aggregates, LLC-
Plant 12/16-01546
Total Number of
Mining Related
Fatalities
Received Notice
of Pattern of
Violations Under
Section 104(e)
(yes/no) (9)
Legal Actions
Pending as of
Last Day of
Period
Legal Actions
Initiated During
Period
Legal Actions
Resolved During
Period
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
1
1
2
1
0
0
0
6
1
1
2
1
0
0
0
3
0
0
0
0
0
0
0
(9) 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 31, 2014
that fall into each of the following categories is as follows:
Mine Name / MSHA
Identification Number
Winn Materials, LLC/40-03094
Laurel Aggregates of Delaware,
LLC/36-08891
Southern Aggregates, LLC-Plant
11/16-01537
Southern Aggregates, LLC-Plant
1/16-01388
Southern Aggregates, LLC-Plant
7/16-01519
Southern Aggregates, LLC-Plant
6/16-00336
Southern Aggregates, LLC-Plant
9/16-01536
Southern Aggregates, LLC-Plant
12/16-01546
Contests
of
Citations
and
Orders
4
1
0
0
0
0
0
0
Contests
of
Proposed
Penalties
2
0
1
2
1
0
0
0
Complaints
for
Compensation
0
0
0
0
0
0
0
0
Complaints of
Discharge/
Discrimination/
Interference
Applications
for
Temporary
Relief
Appeals of
Judges
Rulings
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 99.2
January 21, 2015
Mr. Tim Chung
Natural Resource Partners L.P.
601 Jefferson Street, Suite 3600
Houston, Texas 77002
Dear Mr. Chung:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Natural
Resource Partners L.P. (NRP LP) interest in certain oil and gas properties located in the United States. We completed our evaluation
on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved
reserves owned by NRP LP. The estimates in this report have been prepared in accordance with the definitions and regulations of the
U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the
FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately
following this letter. This report has been prepared for NRP LP’s use in filing with the SEC; in our opinion the assumptions, data,
methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the NRP LP interest in these properties, as of December 31, 2014, to be:
Category
Proved Developed Producing
Proved Developed Non-Producing
Proved Undeveloped
Total Proved
Totals may not add because of rounding.
Future Net Revenue (M$)
Net Reserves
NGL
(MBBL)
Gas
(MMCF)
Oil
(MBBL)
8,918.3 1,092.9 13,069.1 539,307.4 286,178.7
654.8
1,053.3 130.6 1,208.7 47,376.7 18,363.2
305,196.7
9,983.7 1,228.7 14,370.0
92.2 1,032.4
587,716.6
Present Worth
12.1
5.2
at 10%
Total
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of
barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at
standard temperature and pressure bases.
The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties
have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond
those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty;
reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included
herein have not been adjusted for risk.
Gross revenue is NRP LP’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is
after deductions for NRP LP’s share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses
but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine
its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report,
whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
2100 ROSS AVENUE, SUITE 2200
1301 MCKINNEY STREET, SUITE 3200
DALLAS, TEXAS 75201-2737 PH: 214-969-5401 FAX: 214-969-5411
HOUSTON, TEXAS 77010-3034 PH: 713-654-4950 FAX: 713-654-4951
nsai@nsai-petro.com
netherlandsewell.com
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month
in the period January through December 2014. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48
per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of
$4.350 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant
throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the
properties are $82.78 per barrel of oil, $25.00 per barrel of NGL, and $4.406 per MCF of gas.
Operating costs used in this report are based on operating expense records of NRP LP. These costs include the per-well overhead
expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field
levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated,
headquarters general and administrative overhead expenses of NRP LP are not included. Operating costs are not escalated for
inflation.
Capital costs used in this report were provided by NRP LP and are based on authorizations for expenditure and actual costs from
recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our
understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we
regard these estimated capital costs to be reasonable. Abandonment costs used in this report are NRP LP’s estimates of the costs to
abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for
inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical
operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties;
therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the NRP
LP interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such
imbalances; our projections are based on NRP LP receiving its net revenue interest share of estimated future gross production.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those
quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be
economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be
recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations,
changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our
estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current
development plans as provided to us by NRP LP, that the properties will be operated in a prudent manner, that no governmental
regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our
projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom
and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of
supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from
assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data,
historical price and cost information, and property ownership interests. The reserves in this report have been estimated using
deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used
standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we
considered to be appropriate and
necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas
evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions
necessarily represent only informed professional judgment.
The data used in our estimates were obtained from NRP LP, public data sources, and the nonconfidential files of Netherland,
Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not
examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons
responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity,
and confidentiality set forth in the SPE Standards. Steven W. Jansen, a Licensed Professional Engineer in the State of Texas, has been
practicing consulting petroleum engineering at NSAI since 2011 and has over 4 years of prior industry experience. We are
independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are
we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:
By:
/s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
/s/ Steven W. Jansen
Steven W. Jansen, P.E. 112973
Petroleum Engineer
Date Signed: January 21, 2015
SWJ:DEC
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital
document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters,
limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original
document shall control and supersede the digital document.
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included
is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers,
(2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and
Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to
purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees,
recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions
(depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of
interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support
proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of
interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity
greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state
it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but
that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter
(from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively
minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by
means not involving a well.
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open
and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery
project is in operation.
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves
are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started
producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for
mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional
completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively
low expenditure compared to the cost of drilling a new well.
Definitions - Page 1 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering
and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support
equipment and facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining
specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and
power lines, to the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of
platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds,
measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste
disposal systems.
(iv) Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically
producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the
integrated development of a group of several fields and associated facilities with a common ownership may constitute a development
project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to
be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates
revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue
shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and
cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are
considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type
stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as
prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable
operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and
salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are
sometimes referred to as geological and geophysical or “G&G” costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs
for title defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to
be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension
well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
Definitions - Page 2 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by
intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or
adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic
condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays,
areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A)
(B)
(C)
The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural
states and original locations;
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing
the oil or gas from such properties;
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs,
including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other
nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken
with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which
is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to
regard the terminal point for the production function as:
a.
b.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a
refinery, or a marine terminal; and
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are
delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a
common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons
that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A)
(B)
Transporting, refining, or marketing oil and gas;
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that
does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic
oil and gas can be extracted; or
(D)
Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10%
probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves
estimates.
Definitions - Page 3 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of
available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable
to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in
place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative
technical and commercial interpretations within the reservoir or subject project that are clearly documented, including
comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir
within the same accumulation that may be separated from proved areas by faults with displacement less than formation
thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that
such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas
that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation
and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of
the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable
technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and
possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but
which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of
estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that
the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of
available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the
reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if
these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that
could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of
possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related
equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes
called lifting costs) are:
(A)
(B)
Costs of labor to operate the wells and related equipment and facilities.
Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
Definitions - Page 4 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
Severance taxes.
(D)
(E)
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve
transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and
gas producing activities, their depreciation and applicable operating costs become exploration, development or production
costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development
costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs
identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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 that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or
the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A)
The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it
and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists
for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if
geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable
certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when:
(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the
project or program was based; and
(B)
The project has been approved for development by all necessary parties and entities, including governmental
entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered
by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within
such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
Definitions - Page 5 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the
quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually
recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved
than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and
economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or
remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has
been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation
being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there
must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed
means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until
those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly
separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative
test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the
following shall be disclosed as of the end of the year:
a.
b.
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which
the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the
producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be
combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which
reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a.
b.
c.
d.
e.
Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas
reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent
provided by contractual arrangements in existence at year-end.
Future development and production costs. These costs shall be computed by estimating the expenditures to be
incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end
costs and assuming continuation of existing economic conditions. If estimated development expenditures are
significant, they shall be presented separately from estimated production costs.
Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax
rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the
entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses
shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas
reserves.
Future net cash flows. These amounts are the result of subtracting future development and production costs and
future income tax expenses from future cash inflows.
Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the
future net cash flows relating to proved oil and gas reserves.
f.
Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the
computed discount.
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is
confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Definitions - Page 6 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may
be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and
undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells
include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for
in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific
geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also
includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as
“exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of
production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic
producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that
they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or
environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time
periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se
justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though
development may extend past five years include, but are not limited to, the following:
•
•
•
•
•
The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the
minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company’s historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant
development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has
changed its development plan several times without taking significant steps to implement any of those plans, recognizing
proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for
example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal
factors (for example, shifting resources to develop properties with higher priority).
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using
reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 7 of 7
OCI Wyoming LLC
(A Majority-Owned Subsidiary of OCI Resources LP)
Financial Statements as of and for the Years Ended December 31, 2014 and 2013, and Report of Independent Registered Public
Accounting Firm
1
Exhibit 99.3
OCI WYOMING LLC
(A Majority Owned Subsidiary of OCI Resources LP)
TABLE OF CONTENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013:
Balance Sheets
Statements of Operations and Comprehensive Income
Statements of Members’ Equity
Statements of Cash Flows
Notes to Financial Statements
2
Page
Number
3
4
5
6
7
8
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
OCI Wyoming LLC
Atlanta, Georgia
We have audited the accompanying balance sheets of OCI Wyoming LLC (the “Company”) as of December 31, 2014 and 2013, and
the related statements of operations and comprehensive income, members’ equity, and cash flows for the years then ended, and the
related notes to the financial statements. 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).
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, 2014 and 2013, and the results of its operations and its cash flows for the years then ended, in conformity with
accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
February 26, 2015
3
OCI WYOMING LLC
(A Majority Owned Subsidiary of OCI Resources LP)
BALANCE SHEETS
AS OF DECEMBER 31, 2014 AND 2013
(In thousands of dollars)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Accounts receivable - ANSAC
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:
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 — OCI Resources LP
Members’ equity — Natural Resource Partners LP
Accumulated other comprehensive loss
Total members’ equity
TOTAL LIABILITIES AND MEMBERS’ EQUITY
See notes to financial statements.
4
2014
2013
$ 30,520 $ 45,969
34,401
58,051
20,394
41,710
740
201,265
35,457
70,410
19,489
43,237
1,509
200,622
201,402
193,277
880
$402,904
1,231
$395,773
$ 13,069
5,347
29,288
47,704
$ 13,189
375
26,099
39,663
145,000
155,000
4,192
196,896
3,779
198,442
105,445
101,311
(748)
206,008
$402,904
100,919
96,962
(550)
197,331
$395,773
OCI WYOMING LLC
(A Majority Owned Subsidiary of OCI Resources LP)
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013
(In thousands of dollars)
SALES - AFFILIATES
SALES - OTHERS
Total net sales
COST OF PRODUCTS SOLD
FREIGHT COSTS
Total cost of products sold
GROSS PROFIT
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS
LOSS ON DISPOSAL OF ASSETS, NET
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest income
Interest expense
Other income, net
Total other income (expense)
NET INCOME
OTHER COMPREHENSIVE INCOME (LOSS)
Income (loss) on derivative financial instruments
COMPREHENSIVE INCOME
See notes to financial statements.
5
2014
2013
$236,685 $211,645
230,487
442,132
225,160
122,673
347,833
94,299
228,347
465,032
222,848
123,745
346,593
118,439
16,192
12,506
577
36
1,032
100,638
—
81,757
78
(5,140)
1,064
(3,998)
96,640
56
(2,838)
680
(2,102)
79,655
(198)
$ 96,442
30
$ 79,685
OCI WYOMING LLC
(A Majority Owned Subsidiary of OCI Resources LP)
STATEMENTS OF MEMBERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013
(In thousands of dollars)
Balance at January 1, 2013
Allocation of net income through
January 22, 2013
Transfer of interest
Allocation of net income from
January 23, 2013 through July 17,
2013
Restructuring on July 18, 2013
Capital distribution to members through
July 18, 2013
Allocation of net income from July 18,
2013 through September 17, 2013
Restructuring on September 18, 2013
Allocation of net income from
September 18, 2013 through
December 31, 2013
Other comprehensive income (loss)
Balance at December 31, 2013
Allocation of net income
Capital distribution to members
Other comprehensive income (loss)
Balance at December 31, 2014
See notes to financial statements.
OCI
Resources
LP
Natural
Resource
Partners LP
OCI
Wyoming
Holding Co.
Big Island
OCI Wyoming
Co.
Accumulated
Other
Comprehensive
Income (Loss)
Total
Members’
Equity
$ — $
— $ 138,369 $ 132,941 $
9,837 $
(580) $ 280,567
134,038
1,142
1,097
(134,038)
882
15,011
(908)
15,623
(945)
(70,060)
(72,920)
86,841
5,356
4,477
(85,746)
14,078
13,525
7,372
1,853
(19,941)
1,092
(1,095)
$100,919 $ 96,962 $
— $
— $
— $
49,286
(44,760)
47,354
(43,005)
$105,445 $ 101,311 $
— $
— $
— $
3,121
—
38,006
—
(162,921)
10,925
—
27,603
30
(550) $ 197,331
30
96,640
(87,765)
(198)
(198)
(748) $ 206,008
6
OCI WYOMING LLC
(A Majority Owned Subsidiary of OCI Resources LP)
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization
Loss on disposal of assets, net
Other non-cash items
(Increase) decrease in:
Accounts receivable, net
Accounts receivable - ANSAC
Inventory
Other current and non-current assets
Due from affiliates, net
Increase (decrease) in:
Accounts payable
Accrued expenses and other liabilities
Due to affiliates
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
Proceeds from sale of fixed assets
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt
Proceeds from revolving credit facility
Cash distribution to members
Net cash used in financing activities
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS:
Beginning of year
End of year
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Interest paid during the year
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES :
Capital expenditures on account
See notes to financial statements
7
2014
2013
$ 96,640
$ 79,655
21,587
1,032
(203)
(1,055)
(12,359)
(1,499)
(153)
905
(3,535)
3,230
4,971
109,561
(27,255)
10
(27,245)
(10,000)
—
(87,765)
(97,765)
(15,449)
22,723
—
—
809
(4,215)
(45)
(1,470)
5,557
66
(542)
(3,062)
99,476
(16,241)
—
(16,241)
(32,000)
135,000
(162,921)
(59,921)
23,314
45,969
$ 30,520
22,655
$ 45,969
$ 4,274
$ 4,579
$
$
2,285
745
OCI WYOMING LLC
(A Majority Owned Subsidiary of OCI Resources LP)
NOTES TO FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013
(Dollars in thousands)
1. Corporate Structure
A 51% membership interest in OCI Wyoming LLC (the “Company,” “we,” “us,” or “our”) is owned by OCI Resources LP
(“OCIR” or the “Partnership”). Natural Resource Partners LP (NRP) owns a 49% membership interest in the Company. OCIR is
a master limited partnership traded on the New York Stock exchange and is currently owned 74.84% by OCI Wyoming Holding
Co. (OCIWHCO) and 25.16% by the general public. OCI Chemical Corporation (OCICC), which is ultimately 100% owned by
OCI Enterprises, Inc. (OCIE), owns 100% of OCIWHCO. On June 30, 2014, the Company converted from a Delaware limited
partnership to a Delaware limited liability company.
2. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations - The Company operations consist of the mining of trona ore, which, when processed, becomes soda ash.
All soda ash processed is sold through the Company’s sales agent, OCICC, to various domestic and European customers and to
American Natural Soda Ash Corporation (ANSAC) for export. 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 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 sales and services.
Freight Costs - The Company includes freight costs billed to customers for shipments administered by the Company in gross
sales. The related freight costs along with cost of products sold are deducted from gross sales to determine gross profit.
Cash and Cash Equivalents - The Company considers all highly liquid investments purchased with an original maturity of three
months or less to be cash equivalents. Cash equivalents consist primarily of money market deposit accounts.
8
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 2014 and 2013 there were no significant accounts receivable bad debt
expenses, write-offs or recoveries.
Inventory - Inventory and stores inventory is valued at the lower of cost or market on a first-in, first-out basis. Costs include raw
materials, direct labor, and manufacturing overhead. Market is based on current replacement cost for raw materials and stores
inventory and on net realizable value for finished goods. Stores inventory represents parts materials and supplies currently
available for future use.
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 and 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
When property, plant, and equipment are sold or otherwise disposed of, the cost and related accumulated depreciation are
removed from the accounts and any resulting gain or loss is reflected in operations for the year.
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 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.
9
The Company has interest rate swaps recorded within accrued expenses with an aggregate notional value of $76,000 and a fair
value of a liability of $748 at December 31, 2014 and an aggregate notional value of $101,500 and a fair value of a liability of
$550 at December 31, 2013. These contracts are for periods consistent with the exposure being hedged and generally will mature
on July 18, 2018, the maturity date of the long-term debt under our Wyoming Credit Facility.
The Company enters into foreign exchange forward contracts to hedge certain firm commitments denominated in currencies
other than the U.S. dollar. However, the Company does not apply hedge accounting for these contracts. These contracts are for
periods consistent with the exposure being hedged and generally have maturities of one year or less. The fair value of forward
contracts, which are predominantly used to purchase U.S. dollars and sell Euros, totaled an asset of $617 and a liability of $541
at December 31, 2014 and 2013, respectively. These currency hedges have a notional value of $6,900 and $26,360 at
December 31, 2014 and 2013, respectively.
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.
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. As a result of a revised mine reserve study, effective January 1, 2015, the mining reserve will be
amortized over a remaining life of 68 years. During 2014 and 2013 the remaining life was 66 years and 67 years, respectively.
The liability was discounted using the credit-adjusted risk free rate of 7% and is being accreted throughout the estimated life of
the related assets to equal the total estimated costs with a corresponding entry being recorded to interest expense.
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 estimated liability for restoring the rail yard to
its natural condition is 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 entry being recorded to
interest expense.
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,
10
accounts payable and accrued expenses approximate their fair value because of the nature of such instruments. Our interest rate
swaps and foreign exchange contracts are fair valued 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.
Subsequent Events - The Company has evaluated all subsequent events through February 26, 2015, 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. This update is effective for annual reporting periods beginning on or after December 15, 2016 and
interim periods therein and requires expanded disclosures. We are currently assessing the impact the adoption of ASU 2014-09
will have on our consolidated financial statements.
3. ACCOUNTS RECEIVABLE, NET
Accounts receivable, net as of December 31, 2014 and 2013 consists of the following:
Trade receivables
Other receivables
Allowance for doubtful accounts
Total
4. INVENTORY
Inventory as of December 31, 2014 and 2013 consists of the following:
Raw materials
Finished goods
Stores inventory
Total
11
2014
$24,691
10,854
35,545
(88)
$35,457
2013
$23,888
10,522
34,410
(9)
$34,401
2014
2013
$ 6,413 $ 5,754
10,496
25,460
$41,710
10,363
26,461
$43,237
5. PROPERTY, PLANT, AND EQUIPMENT, NET
Property, plant, and equipment as of December 31, 2014 and 2013 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
2014
$
192
2,957
129,514
4,468
567,289
704,420
(536,163)
168,257
33,145
$ 201,402
2013
$
192
1,982
128,927
4,141
566,361
701,603
(531,191)
170,412
22,865
$ 193,277
Depreciation, depletion and amortization expense on property, plant and equipment was $21,235 and $22,723, for the years
ended December 31, 2014 and 2013, respectively.
6. ACCRUED EXPENSES
Accrued expenses as of December 31, 2014 and 2013 consists of the following:
Accrued freight costs
Accrued energy costs
Accrued royalty costs
Accrued employee compensation
Accrued other taxes
Accrued derivatives
Other accruals
Total
2014
2013
$ 1,373 $
5,718
4,445
6,739
4,608
748
5,657
$29,288
464
6,128
3,995
5,116
4,154
1,091
5,151
$26,099
7. DEBT
Long-term debt as of December 31, 2014 and 2013 consists of the following:
Variable Rate Demand Revenue Bonds, principal due October 1, 2018,
interest payable monthly, bearing monthly interest rate of 0.14%
(2014) and 0.16% (2013)
Variable Rate Demand Revenue Bonds, principal due August 1, 2017,
interest payable monthly, bearing monthly interest rate of 0.14%
(2014) and 0.16% (2013)
OCI Wyoming Credit Facility, unsecured principal due July 18, 2018,
interest payable quarterly, bearing quarterly variable interest at
1.9781% (2014) and 1.996% (2013).
Total debt
Less current portion of long-term debt
Total long-term debt
2014
2013
$ 11,400
$ 11,400
8,600
8,600
125,000
145,000
—
$145,000
135,000
155,000
—
$155,000
12
Aggregate maturities required on long-term debt at December 31, 2014 are as follows:
2017
2018
Total
Revenue Bonds
$ 8,600
136,400
$145,000
The above revenue bonds require the Company to maintain standby letters of credit totaling $20,333 at December 31, 2014.
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, 2014, the Company was in compliance with these debt covenants.
OCI 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 “OCI Wyoming Credit Facility”), with a syndicate of lenders, which will mature on the fifth anniversary
of the closing date of such credit facility. The OCI Wyoming Credit Facility provides for revolving loans to fund working capital
requirements, capital expenditures, to consummate permitted acquisitions and for all other lawful Company purposes. The OCI
Wyoming Credit Facility has an accordion feature that allows OCI 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 OCI 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 OCI Wyoming Credit Facility are unsecured.
The OCI 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 OCI Wyoming Credit Facility also requires quarterly maintenance of a leverage ratio (as defined in the OCI Wyoming
Credit Facility) of not more than 3.00 to 1.00 and a fixed charge coverage ratio (as defined in the OCI Wyoming Credit Facility)
of not less than 1.10 to 1.00 for the 2014 and 2015 fiscal years, respectively and not less than 1.15 to 1.00 thereafter. The OCI
Wyoming Credit Facility also requires that consolidated capital expenditures, as defined in the OCI Wyoming Credit Facility,
not exceed $50 million in any fiscal year.
In addition, the OCI Wyoming Credit Facility contains events of default customary for transactions of this nature, including
(i) failure to make payments required under the OCI Wyoming Credit Facility, (ii) events of default resulting from failure to
comply with covenants and financial ratios in the OCI Wyoming Credit Facility, (iii) the occurrence of a change of control,
(iv) the institution of insolvency or similar proceedings against OCI Wyoming and (v) the occurrence of a default under any
other material indebtedness OCI Wyoming may have. Upon the occurrence and during the continuation of an event of default,
subject to the terms and conditions of the OCI Wyoming Credit Facility, the lenders may terminate all outstanding commitments
under the OCI Wyoming Credit Facility and may declare any outstanding principal of the OCI Wyoming Credit Facility debt,
together with accrued and unpaid interest, to be immediately due and payable.
13
Under the OCI Wyoming Credit Facility, a change of control is triggered if OCI Chemical 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 OCIR (or any entity that performs the functions the general
partner of OCIR). In addition, a change of control would be triggered if OCIR 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.
The Company was in compliance with all terms under its long-term debt agreements as of December 31, 2014.
Loans under the OCI 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 and (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 OCI 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.
8. OTHER NON-CURRENT LIABILITIES
Other non-current liabilities as of December 31, 2014 and 2013 consists of the following:
Reclamation reserve at beginning of year
Accretion expense
Reclamation reserve at end of year
9. EMPLOYEE BENEFIT PLANS
2014
$3,779
413
$4,192
2013
$3,560
219
$3,779
The Company participates in various benefit plans offered and administered by OCIE and is allocated its portions of the annual
costs related thereto. The specific plans are as follows:
Retirement Plans - Benefits provided under the OCI Pension Plan for Salaried Employees and OCI 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. OCIE’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 $3,140 and $8,421 for the years ended
December 31, 2014 and 2013, respectively. The decrease in pension costs was driven by favorable effects of higher actuarial
discount rates and market returns.
Savings Plan - The OCI 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, 2014 and 2013 were $2,428 and $2,795, 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.
14
OCIE accounts for postretirement benefits on an accrual basis over an employee’s period of service. The postretirement plan,
excluding pensions, are not funded, and OCIE 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 OCIE’s postretirement benefits decreased by $8.7 million and resulted in a prior service credit of $7.7 million
which will be recognized as a reduction of net periodic postretirement benefit costs in future years. The Company’s allocated
portion of postretirement benefit costs was income of $260 and $55 for the years ended December 31, 2014 and 2013,
respectively.
10. 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.
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 a 10 year track lease agreement with Union Pacific Company for certain rail track used in connection
with the rail yard.
OCICC, on behalf of the Company, typically enters into operating lease contracts with various lessors for railcars to transport
product to customer locations and warehouses. Rail car leases under these contractual commitments range for periods from 1 to
10 years. OCICC’s obligations related to these rail car leases are $9,664 in 2015, $7,153 in 2016, $5,665 in 2017, $4,402 in
2018, $3,585 in 2019 and $4,421 in 2020 and thereafter.
As of December 31, 2014, the total minimum rental commitments under the Company’s various operating leases, including
renewal periods are as follows:
2015
2016
2017
2018
2019
2020 and thereafter
Total
Leased Land
75
$
75
75
75
75
1,575
1,950
$
Track Lease
33
$
33
33
33
33
66
231
$
Total
$ 108
108
108
108
108
1,641
$2,181
From time to time, the Company has various litigation, claims, and assessments that arise in the normal course of business.
Management does not believe, based upon its evaluation and discussion with counsel, that the ultimate outcome of any current
matters, individually or in the aggregate, would have a material effect on the Company’s financial position, results of operations,
or cash flows.
Off-Balance Sheet Arrangements - The Company has a self-bond agreement with the Wyoming Department of Environmental
Quality under which we commit to pay directly for reclamation costs. As of December 31, 2014, the amount of the bond was
$33,875, 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 increased in August 2013 and is subject to change upon periodic re-evaluation by the
Land Quality Division.
15
11. AFFILIATES TRANSACTIONS
OCICC is the exclusive sales agent for the Company and through its membership in ANSAC, OCICC 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 OCICC are charged directly to the Company. Selling, general and administrative expenses also
include amounts charged to the Company by OCIE, OCICC, and OCIR principally consisting of salaries, benefits, office
supplies, professional fees, travel, rent and other costs of certain assets used by the Company. These transactions do not
necessarily represent arm’s length transactions and may not represent all costs if the Company operated on a standalone basis.
The total costs charged to the Company by affiliates for the years ended December 31, 2014 and 2013 are as follows:
2014
2013
OCIE
OCICC
ANSAC
OCIR
Total selling, general and administrative expenses - affiliates
$ 8,955 $ 5,537
4,387
2,582
—
$12,506
3,415
2,930
892
$16,192
ANSAC allocates its expenses to ANSAC’s 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, 2014 and 2013 these
costs were $9,194 and $6,692, respectively.
Net sales to affiliates for the years ended December 31, 2014 and 2013 are as follows:
ANSAC
OCI Alabama LLC
OCI Company Limited
Total
2014
$230,762
5,923
—
$236,685
2013
$200,413
7,282
3,950
$211,645
As of December 31, 2014 and 2013, the Company had receivables and payables representing arm’s length transactions with
affiliated entities as follows:
OCIE
OCICC
OCI Chemical Europe NV
OCI Company Limited
Other
Total
2014
2013
Receivables from
Affiliates
Payables to
Affiliates
Receivables from
Affiliates
Payables to
Affiliates
1,594 $
8,268
9,183
—
444
19,489
$
2,848 $
1,171
—
—
1,328
5,347
$
110 $
10,460
7,822
1,919
83
20,394
$
252
—
—
—
123
375
$
$
16
12. 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, 2014 and 2013 are as
follows:
Domestic
International:
ANSAC
Other
Total international
Total net sales
2014
$194,801
2013
$195,062
230,762
39,469
270,231
$465,032
200,413
46,657
247,070
$442,132
The Company’s largest customer by sales is ANSAC. There were no other customers who individually accounted for ten percent
or more of total net sales for the years ended December 31, 2014 and 2013.
13. SUBSEQUENT EVENTS
On January 15, 2015, the members of the board of managers of OCI Wyoming LLC approved the payment on January 16, 2015
of a cash distribution to the general partners and the limited partners in the aggregate amount of $22,250.
In February 2015, the Company entered into a natural gas forward contract with a notional value of approximately $17,568 and
maturity dates ranging from 2015 to 2020, to mitigate volatility in the gas prices. The maturity of the notional value is $911 in
2015, $2,889 in 2016, $3,179 in 2017, $3,385 in 2018, $3,552 in 2019 and $3,652 in 2020.
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17
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Unitholder Information
Information regarding Natural Resource Partners L.P. is located on the partnership’s website.
On the site are 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 all Board of Directors’ Committee Charters. Requests for copies
of the annual report or other data may be made through the website or by contacting Investor
Relations 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
601 Jefferson, Suite 3600
Houston, TX 77002
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 the end of February. 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, aggregates and oil and gas 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.
Partnership Headquarters
601 Jefferson Street
Suite 3600
Houston, TX 77002
713.751.7507
Operations Headquarters
5260 Irwin Road
Huntington, WV 25705
304.522.5757
Investor Relations
Kathy Roberts
601 Jefferson Street
Suite 3600
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 & 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
WN
Design: Savage Brands, Houston TX
Natural Resource Partners L.P.
601 Jefferson Street
Suite 3600
Houston, TX 77002
www.nrplp.com