MOVING
FORWARD
NATURAL RESOURCE PARTNERS L.P.
2013 ANNUAL REPORT
Natural Resource Partners L.P. is principally engaged
Natural Resource Partners L.P. is principally engaged
in the business of owning and managing mineral
in the business of owning and managing mineral
reserve properties. Since our initial public offering
reserve properties. Since our initial public offering
in 2002, we have diversified the company’s assets
in 2002, we have diversified the company’s assets
through sound, strategic acquisitions designed to
through sound, strategic acquisitions designed to
generate income for the partnership and provide
generate income for the partnership and provide
future growth. Today NRP owns more than 11 million
future growth. Today NRP owns more than 11 million
mineral acres that consist of coal, aggregates, oil
mineral acres that consist of coal, aggregates, oil
and gas, and other minerals. In addition, NRP owns
and gas, and other minerals. In addition, NRP owns
non-operated working interests in oil and gas
non-operated working interests in oil and gas
properties and an equity interest in a trona ore
properties and an equity interest in a trona ore
mining and soda ash refining operation.
mining and soda ash refining operation.
DIVERSIFYING
DIVERSIFYING
FOR
FOR
2005 REVENUES
TOTAL =
$159.1MM
28% Met Coal
54% Thermal Coal – APP
3% Thermal Coal – ILB
5% Thermal Coal – NPRB
4% Coal Infrastructure,
ORRI & Minimums
2% Oil & Gas
4% Other
2013 REVENUES
25% Met Coal
5% Other
5% Oil & Gas
13% Aggregates &
GROWTHWT
16% Thermal Coal – APP
Industrial Minerals
16% Thermal Coal – ILB
17% Coal Infrastructure, ORRI,
Minimums & Other
2% Thermal Coal – NPRB
1% Thermal Coal – GC
TOTAL = $358.1MM
2013 (cid:96) ANNUAL REPORT
1
MOVING FORWARD TO
A MORE DIVERSIFIED FUTURE
As the world of energy keeps changing, Natural Resource Partners continues to move
forward with a strategy of diversification that has enabled us to keep pace. Last year,
41 percent of our revenues came from sources other than coal royalties, compared with
31 percent in 2012 and just 10 percent in 2005. This demonstrates our commitment to
a more diverse range of assets and revenue streams, and ensures that Natural Resource
Partners can execute our business plan with confidence, purpose, and vision now –
and in the future.
COAL
Even as we have diversified, coal has
remained an important contributor to
our revenue stream and resource base.
We own coal reserves in the three major
U.S. producing regions. We own or control
approximately 2.3 billion tons of proven
and probable coal reserves, and we gener -
ated more than $212 million from coal royalty
revenues in 2013.
AGGREGATES
& INDUSTRIAL MINERALS
We purchased our first aggregates property
in 2006 and have since made additional
acquisitions in multiple regions of the
United States. Aggregates and industrial
minerals – which are used in nearly every
residential, commercial, industrial and public
works construction project – accounted for
$41.8 million in revenues in 2013.
OIL & GAS
Our diversification into oil and gas has
given us a foothold in some of the most
important U.S. producing regions. Last year
we generated $17.1 million in revenues from
our interests in oil and gas properties – more
than five times the total in 2005 – and we are
focused on further growing this business. In
fact, in 2014 we expect oil and gas revenues
to more than double over 2013.
2
NATURAL RESOURCE PARTNERS L.P.
TRONA/SODA ASH
ACQUISITION
WILLISTON BASIN
ACQUISITIONS
FUTURE NATURAL
RESOURCE ACQUISITIONS
Our investment in OCI Wyoming’s trona
ore mining operation and soda ash refinery
brought total distributions of $72.9 million
in 2013, including a special distribution of
$44.8 million. These cash distributions not
only enabled us to mitigate the effects
of a softer coal market, but also further
reinforced the effectiveness of our
diversification strategy.
2013 (cid:96) ANNUAL REPORT
We acquired non-operating working interests
from Abraxas Petroleum and Sundance
Energy in the Bakken and Three Forks plays
in the Williston Basin that included both
producing wells and additional development
locations. This marked our strategic entry
into one of North America’s top producing
regions and into owning non-operated
working interests in the oil and gas sector.
These assets will further diversify our
revenues going forward.
We will continue to pursue additional
accretive natural resource acquisitions
that will further diversify and grow our
revenues creating additional value for
our unitholders.
3
TO OUR UNITHOLDERS
In 2013, Natural Resource Partners demonstrated once again that we are
able to execute our business plan despite a changing energy environment
that has presented significant challenges. We reinforced our strategy to
diversify our company with more than $365 million in sound, accretive
acquisitions outside the coal space, allowing us to minimize the effects of
weaker coal markets. By continuing our efforts to expand our asset base
beyond our core coal royalty business – including a growing presence in
the oil and gas sector and a significant investment in a trona mining and
soda ash business – we are underscoring our commitment to generate
stable to growing cash flows and deliver value to our unitholders.
Moving Forward Despite Continuing Challenges
At year end, Natural Resource Partners had approximately
By any measure, the coal market in 2013 was the toughest
$390 million in liquidity, including $93 million in cash and
we have seen since our inception in 2002. But by remaining
$296 million in available capacity under our credit facilities.
focused on our current asset base while pursuing a disciplined
We believe that this liquidity provides us the flexibility neces-
acquisition strategy, Natural Resource Partners was able to
sary to continue to pursue strategic acquisitions to create
effectively manage through the difficult market conditions
more – and more diverse – opportunities for growth.
we faced:
Even in an Uncertain Market, Positive Signals for Coal
• Our distributable cash flow increased $10 million to
There is little doubt that the expansion of domestic energy pro-
$309 million due to the $73 million in cash distributions
duction, especially natural gas, has had a profound impact on
received from our investment in OCI Wyoming, which
the coal industry. However, coal remains an essential fuel, and
offset other declines.
• Revenues other than coal royalty revenues increased
to 41 percent of total revenues in 2013 as compared to
31 percent of total revenues in 2012. The increase was
primarily due to revenues associated with the investment
in OCI Wyoming, as well as increases in aggregates and
industrial minerals and oil and gas revenues.
there are clear indications it will continue to be for some time to
come. The U.S. Energy Information Administration has forecast
that total U.S. coal production will increase from 1,016 million
short tons in 2012 to 1,062 million short tons in 2015, to 1,121
short tons in 2040. The agency further projects that coal
consumption will increase for the 10 years that begin in 2016.
4
NATURAL RESOURCE PARTNERS L.P.
Financial Highlights
(in millions, except per unit)
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
For the year ended December 31
Total Revenues
$ 358 $ 379
$ 378 $ 301 $ 256 $ 292 $ 215 $ 171 $ 159 $
Income from operations
Net income
Net income before
236
172
267
104
213
54
196
154
154
114
197
170
128
102
116
101
102
92
59
121
71
considering impairments
173
216
215
154
114
170
102
102
92
59
Net income per unit
$ 1.54 $ 1.97 $
.50 $ 1.54 $
1.17 $ 1.95 $
1.11 $ 1.60 $
1.71 $
1.12
Net income per unit before
considering impairments
Distributions per unit
Weighted average number
of units outstanding
Cash from operations
Balance sheet data (at December 31)
1.55
2.00
2.00
2.20
110
106
1.99
2.18
106
1.54
2.16
82
1.17
2.16
68
1.95
2.07
65
1.11
1.88
65
1.60
1.67
51
1.71
1.45
51
1.12
1.24
50
$ 247 $ 271 $ 306 $ 259 $ 211 $ 230 $ 168 $ 139 $
122 $
91
Cash and cash equivalents
$
93 $ 149
$ 215 $
96 $
83 $
90 $
58 $
66 $ 48 $
42
Total assets
Long-term debt
Partner’s capital
1,992
1,084
617
1,765
897
617
1,666
836
645
1,664
661
825
1,524
627
765
1,301
479
743
1,320
496
745
939
454
436
685
222
426
600
156
409
04
05
06
07
08
09
10
11
12
13
$121
$159
Total Revenues
Thermal Coal
Metallurgical Coal
royalty revenue
$171
Other Coal-related
revenues
$215
Aggregates and
Industrial Minerals
$292
Oil & Gas
Other
$ in millions
$256
$301
$378
$379
$358
2013 (cid:96) ANNUAL REPORT
5
COAL
2.3B
~70
AGGREGATES
NRP owns 2.3 billion tons of coal reserves
500MM
NRP owns approximately 500 million
tons of aggregate reserves
NRP leases coal to approximately
70 lessees
13states
NRP owns reserves in 13 states
53MM
NRP’s lessees produced approximately
53 million tons of coal from NRP’s
properties in 2013
49%
NRP owns a 49% equity interest in
OCI Wyoming, a trona mining and
soda ash refining operation
Finally, EIA forecasts that after a decline in 2013, coal exports
OCI Wyoming operates a trona ore mining operation and
will increase to 161 million short tons in 2040, and remain an
soda ash refinery in the Green River Basin in Wyoming. The
important part of the energy economy due to global demand
soda ash produced is used in a wide variety of consumer
being fueled in large part by China and India.
products, including glass, chemicals, soap, and paper. In
At the same time, there are some positive near-term signals
for coal. A cold winter in 2013–2014 resulted in higher natural
gas prices and lower gas storage levels. Beyond that, utilities
ran their coal-fired units at near full capacity this winter, and
coal stockpiles have been reduced below their five year aver-
age levels. Entering 2014, utilities had a larger spot position
than they have had in the past, and the reduced stockpiles
2013, we received total cash distributions of $72.9 million
from OCI Wyoming, including a $44.8 million special one- time
distribution, and expect to receive approximately $40 million
per year in cash distributions going forward. These cash dis-
tributions not only helped us dampen the effects of the soft
coal markets, but also demonstrate the effectiveness of our
diversification strategy.
could require them to purchase thermal coal at higher prices
Additionally, we completed two acquisitions in the second
on the spot market during peak heating and cooling seasons.
half of 2013, which give us a presence in the Williston Basin in
In addition, during the cold winter, gas storage levels were
North Dakota and Montana, including interests in the Bakken
reduced significantly lower than normal and will need to be
and Three Forks plays, which area has been one of the main
refilled before next winter. These conditions should lead to
engines of growth in U.S. oil production. We purchased non-
higher thermal coal prices. This in combination with higher
operating working interests in oil and gas properties from
natural gas prices has the potential to deliver significant
Abraxas Petroleum and Sundance Energy that at year end
potential benefits to our coal and natural gas interests as
included interests in 218 producing wells and 40 wells in
well as value to our unitholders.
We are further cushioned from uncertainties in the coal markets
by our diversified assets and revenue streams. Natural Resource
Partners now has interests in some of the most important
oil and gas producing regions in the country, including the
Williston Basin and the Appalachian Basin. In addition, we
continue to experience growth in our aggregates and indus-
trial minerals business, the markets for which have remained
stable and are expected to grow as the economy strengthens.
OCI Wyoming and Williston Basin Acquisitions Drive
2013 Performance
The overall performance of Natural Resource Partners in 2013
was bolstered by two significant achievements: The success
of our investment in OCI Wyoming and our entry into the
Williston Basin in North Dakota and Montana.
various stages of development. These acqui sitions were
immediately accretive to our unitholders and are expected
to generate increasing revenues as development of our
properties continues.
“ I am confident that Natural Resource
Partners will continue moving forward
toward a future of growth and diversi-
fication of assets, revenue streams,
and sources of cash flow.”
Corbin J. Robertson, Jr.
6
NATURAL RESOURCE PARTNERS L.P.
OIL & GAS
ACQUISITIONS
1,300
+
NRP owns interests in more
than 1,300 gross oil and
gas wells
261,000
+
NRP owns more than
261,000 net leased
mineral acres
100,000
+
NRP has leasehold or overriding
royalty interests in more than
100,000 net leasehold acres
Focused on diversification of assets
Oil and gas acquisitions are focused on non-operated working
interests, royalty interests and joint-venture partnerships in
low-risk, onshore basins
Aggregates and industrial minerals acquisitions are focused
on acquisitions of mineral and royalty interests in a multitude
of aggregates and industrial minerals as well as joint-venture
partnerships or equity interests similar to our OCI investment
Coal acquisitions are focused on Illinois Basin reserves
or infrastructure with a minor interest in acquisition of
metallurgical coal reserves
Looking Ahead: Fully Prepared to Meet Any Challenge
This optimism is founded on our belief that we have the lead-
Moving Forward
ership to continue NRP’s growth and diversification. Over our
At Natural Resource Partners, we understand that the
11-plus years as a public company, we have con sistently been
domestic and global energy environments are continuing
able to create acquisition opportunities. In preparing for our
to evolve and present us with ever-more-difficult challenges.
future, we have just completed a two-year succession and
The regulatory climate is uncertain. The metallurgical coal
strategic planning process. As we approached Nick Carter’s
market remains weak, and exports from Australia will have
retirement (whom we wish well), we have focused on who
an impact on prices in the United States. While worldwide
was best qualified to lead NRP through future generations.
demand for steel is stable, metallurgical coal production,
Effective September 1, we have promoted Wyatt Hogan to
used in making steel, is outpacing demand. Yet even in the
serve as President and Kevin Wall to Chief Operating Officer,
midst of all these issues, Natural Resource Partners is well
who each have a wealth of experience both inside and outside
positioned to manage through adverse market issues.
of NRP. The NRP team has the broad, deep experience neces-
Simply stated, we are fully prepared to meet the challenges
that the future may hold. Our decision in early 2014 to reduce
quarterly distributions will enable us to preserve our liquidity
and continue to diversify. We have the financial flexibility
sary to execute our strategy and identify acquisitions that
benefit our unitholders as market conditions change. Our
team understands our assets and income, they are leading
our strategy, and they share our vision.
to continue to execute sound, accretive acquisitions that
With that kind of commitment, I am confident that Natural
will broaden our asset base and revenue streams and allow
Resource Partners will continue moving forward toward
us to continue to meet the challenges in the coal markets.
a future of growth and diversification of assets, revenue
We expect significant growth in revenues from our growing
presence in oil and gas, and believe that the domestic soda
ash market will remain stable while the international market
improves. We have a strong presence in the Illinois Basin,
whose coal is becoming increasingly attractive again – and
whose production is expected to increase by the end of this
decade – thanks to advances in scrubbing technology. This
combination of a practical, forward-looking business plan,
diverse resources, and financial strength gives us the con-
fidence of knowing we can negotiate the shifts, changes,
and turns that may lie ahead.
streams, and sources of cash flow.
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
2013 (cid:96) ANNUAL REPORT
7
Directors & Officers
BOARD OF DIRECTORS
OFFICERS
Corbin J. Robertson, Jr.
Chairman and Chief Executive Officer
Nick Carter
President and Chief Operating Officer
Dwight L. Dunlap
Chief Financial Officer and Treasurer
Wyatt L. Hogan
Executive Vice President
Kevin F. Wall
Executive Vice President – Operations
Dennis F. Coker
Vice President – Aggregates
Kevin J. Craig
Vice President – Business Development
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
Kenneth Hudson
Controller
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)
United Coal Company, LLC
Chairman of the Board of Directors
Secure Energy, LLC
Advisory Board Member
Corbin J. Robertson III
LKCM Headwater Investments GP, LLC
Co-Managing Partner
Stephen P. Smith (1) (3) (4)
NiSource, Inc.
Executive Vice President and Chief Financial Officer
Leo A. Vecellio, Jr. (2) (4)
Vecellio Group, Inc.
Chairman and Chief Executive Officer
8
NATURAL RESOURCE PARTNERS L.P.
(1) Audit Committee
(2) Nominating and Compensation Committee
(3) Conflicts Committee
(4) Independent Directors
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, 2013 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 $1.5 billion on June 30, 2013 based on a price of $20.57 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 28, 2014, there were 109,812,408 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
2
26
41
41
41
41
42
43
46
66
67
92
92
93
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 Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
94
101
111
112
119
10.
11.
12.
13.
14.
15.
Exhibits, Financial Statement Schedules
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
123
PART IV
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, hydrocarbons, aggregates and industrial minerals;
• estimated revenues, expenses and results of operations;
• the amount, nature and timing of capital expenditures;
• our ability to make acquisitions;
• our liquidity and access to capital;
• projected production levels by our lessees;
• OCI Wyoming, L.P.’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” 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 mineral properties in the
United States. We own coal reserves 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. As of December 31,
2013, we owned or controlled approximately 2.3 billion tons of proven and probable coal reserves. We do not
operate any 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 for our company, particularly in the Illinois Basin.
We have made a concerted effort to diversify our business in recent years. In 2013, we spent over
$365 million to acquire interests in non-coal-related operating businesses. In January 2013, we acquired a non-
controlling equity interest in OCI Wyoming, L.P., an operator of a trona ore mining operation and a soda ash
refinery in the Green River Basin, Wyoming for $292.5 million. We also completed two acquisitions of non-
operated working interests in oil and gas operations in the Williston Basin of North Dakota and Montana for an
aggregate purchase price of $72 million. In addition, we own various interests in oil and gas properties that are
located in other areas, including the Appalachian Basin, Louisiana and Oklahoma, and we own approximately
500 million tons of aggregate reserves located in a number of states across the country.
For the year ended December 31, 2013, we recognized approximately $145.5 million (40.6%) of our
revenues and other income from sources other than coal royalties, which primarily consisted of equity income
from our investment in OCI Wyoming, oil and gas revenues, aggregates royalties, overriding royalties (which
include coal and aggregates overrides), minimums recognized as revenue, and processing and transportation fees.
The revenues that we recognize from minimums and processing/transportation are largely derived from coal-
related businesses.
In our coal and aggregate royalty business, our lessees generally make payments to us based on the greater
of a percentage of the gross sales price or a fixed royalty per ton of coal or aggregates they sell, subject to
minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a
specified period of time, which varies by lease, if sufficient royalties are generated from production in those
future periods. We do not recognize these minimum royalties as revenue until the applicable recoupment period
has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are
recorded as deferred revenue, a liability on our balance sheet.
Oil and gas royalty revenues include production payments as well as bonus payments. Oil and gas royalty
revenues 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. 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 in oil and gas
assets.
2
Partnership Structure and Management
Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our
subsidiaries 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
Resource Partners LLC makes 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.
Our operations headquarters 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.
Royalty Business
Royalty businesses principally own and manage mineral reserves. As an owner of mineral reserves, we
typically are not responsible for operations on our 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 us and are required to report tons of coal or
aggregates removed as well as the sales prices of the extracted minerals. Therefore, to a great extent, amounts
reported as royalty revenue are based upon the reports of our lessees. We periodically audit this information by
examining certain records and internal reports of our lessees, and we perform periodic mine inspections to verify
that the information that our lessees have submitted to us is accurate. Our audit and inspection processes are
designed to identify material variances from lease terms as well as differences between the information reported
to us and the actual results from each property. Our 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 royalty revenue was initially recorded.
Our royalty revenues are affected by changes in long-term and spot commodity prices, production volumes,
unseasonal weather, lessees’ supply contracts and the royalty rates in our leases. The prevailing prices for coal
and oil and gas depend on a number of factors, including the supply-demand relationship, the price and
availability of alternative fuels, global economic conditions and governmental regulations. The prevailing price
for aggregates generally depends on local and in some cases, global, economic conditions. In addition to their
royalty obligation, 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. We do not typically receive minimum royalties with respect to our oil and gas properties, although we
do have some leases with minimum annual payments or delay rental provisions, but do typically receive bonus
payments at the time of execution of the lease.
3
Because we do not operate any mines, our 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 aggregate
properties. We typically pay property taxes on our properties, which are then reimbursed by the lessee pursuant
to the terms of the lease.
Acquisitions
We are a growth-oriented company and have completed a number of acquisitions. For a discussion of our
recent acquisitions, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Recent Acquisitions.”
Coal Royalty Revenues, Reserves and Production
The following summary table sets forth coal royalty revenues and average coal royalty revenue per ton from
the properties that we owned or controlled for the years ending December 31, 2013, 2012 and 2011. Coal royalty
revenues were generated from the properties in each of the areas as follows:
Coal Royalty Revenues
For the Years Ended
December 31,
Average Coal Royalty
Revenue Per Ton
For the Years Ended
December 31,
2013
2012
2011
2013
2012
2011
(In thousands)
($ per ton)
Area
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 14,643 $ 15,768
156,390
105,004
29,325
26,156
$ 20,578
$1.27
196,789 $5.05
11,717 $6.30
$1.50
$3.92
$5.99 $6.66
$7.89 $6.91
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
229,084 $4.00
41,324 $4.28
$2.72
$3.39
7,658
1,155
$5.00 $6.28
$4.38 $4.38
$3.58 $2.86
$2.60 $2.21
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$212,663 $260,734 $279,221 $3.99
$4.79 $5.68
4
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, 2013, 2012 and 2011. 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 the Year
Ended
December 31,
Proven and Probable Reserves at
December 31, 2013
2013
2012
2011
Underground
Surface
Total
(Tons in thousands)
Area
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,505 10,486
5,251
20,801 26,098 29,555
1,695
3,718
4,151
478,448
1,024,366
86,670
29,333
507,781
230,082 1,254,448
111,605
24,935
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36,457 40,302 36,501
9,445
13,087 11,299
2,682
2,377
2,778
523
466
970
1,589,484
340,758
284,350 1,873,834
354,761
14,003
97,002
— 97,002
3,737
3,737
—
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53,292 54,444 49,151
1,930,242
399,092 2,329,334
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,
2013, 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 Form 10-K on an as-received basis,
which assumes 6% moisture for Appalachian reserves, 12% moisture for Illinois Basin 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 2013, approximately 31% of the production and 41% of
the coal royalty revenues from our properties were from metallurgical coal.
5
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, 2013.
Sulfur Content, Typical Quality and Type of Coal
Sulfur Content
Compliance
Coal(1)
Low
(less than
1.0%)
Medium
(1.0% to
1.5%)
High
(greater
than 1.5%)
Total
Heat Content
(Btu per pound)
Sulfur
(%)
Type of Coal
Steam Metallurgical(2)
(Tons in thousands)
(Tons in thousands)
Typical Quality
Area
Appalachia
Northern . . . . . . . .
Central
Southern . . . . . . . .
50,374
. . . . . . . . . 622,692
74,756
73,094 24,466 410,221
891,119 312,030
80,820 27,787
507,781
51,299 1,254,448
111,605
2,998
Total Appalachia . . . . 747,822 1,045,033 364,283 464,518 1,873,834
354,761
Illinois Basin . . . . . . .
Northern Powder
— 2,193 352,568
—
12,836
13,274
13,507
13,169
11,499
2.59
0.89
0.83
498,219
859,404
79,224
1.35 1,436,847
354,761
3.27
9,562
395,044
32,381
436,987
—
River Basin . . . . . .
Gulf Coast . . . . . . . . .
—
128
97,002
3,737
—
—
—
—
97,002
3,737
8,800
6,913
0.65
0.69
97,002
3,609
—
128
Total
. . . . . . . . . . . . . 747,950 1,145,772 366,476 817,086 2,329,334
1,892,219
437,115
(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. Some of these factors and assumptions include:
• future coal prices, mining economics, capital expenditures, severance and excise taxes, and development
and reclamation costs;
• future mining technology improvements;
• the effects of regulation by governmental agencies; and
• geologic and mining conditions, which may not be fully identified by available exploration data and may
differ from our experiences in other areas of our reserves.
As a result, actual coal tonnage recovered from identified reserve areas or properties may vary from
estimates or may cause our estimates to change from time to time. Any inaccuracy in the estimates related to our
reserves could result in royalties that vary from our expectations.
6
Major Coal Properties
The following is a summary of our major coal producing properties in each region:
Northern Appalachia
AFG-Ohio.
The AFG-Ohio property is located in Belmont County, Ohio. In 2013, 4.9 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. Coal is shipped by rail and barge to customers including AEP,
Duke Energy and First Energy.
Hibbs Run.
The Hibbs Run Property is located in Marion County, West Virginia. In 2013, 3.5 million
tons were produced from the property. During 2013, the lessee was acquired by Murray Energy Corporation.
Coal from this property is produced from longwall mines. The royalty rate for this property is a low fixed rate per
ton and has a significant effect on the per ton revenue for the region. 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
2013, 2.2 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. It 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-Central PA.
The AFG-Central PA property is located in Cambria and Indiana Counties,
Pennsylvania. In 2013, 407,000 tons were produced from this property. We lease this property primarily to
subsidiaries of Rosebud Mining Company and Alpha Natural Resources. Coal from this property is produced
primarily from underground mines and the production is transported by truck or rail to utility customers and a
portion is sold on the metallurgical market.
7
The map below shows the location of our properties in Northern Appalachia.
8
Central Appalachia
VICC/Alpha.
The VICC/Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties,
Virginia. In 2013, 4.2 million tons were produced from this property. We primarily lease this property to a
subsidiary of Alpha Natural Resources. 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 and Patriot Coal. In 2013, 3.2 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.
VICC/Kentucky Land.
The VICC/Kentucky Land property is located primarily in Perry, Leslie and Pike
Counties, Kentucky. In 2013, 2.4 million tons were produced from this property. Coal is produced from a number
of lessees, including subsidiaries of TECO and James River, 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 2013, 1.7 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.
Lynch.
The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2013, 1.4 million
tons were produced from this property. We primarily lease the property to a subsidiary of Alpha Natural
Resources. Production comes from both underground and surface mines. This property has the ability to ship coal
on both the CSX and Norfolk Southern railroads. In late 2012, the lessee idled a preparation plant on CSX
railroad that primarily served the utility markets. The preparation plant on the CSX railroad was restarted on a
limited basis in early 2014. During 2013, coal was primarily belted and trucked to a preparation plant and
shipped on the Norfolk Southern railroad to metallurgical and utility customers.
Kingston.
The Kingston property is located in Fayette and Raleigh Counties, West Virginia. This property
is leased to a subsidiary of Alpha Natural Resources. In 2013, 1.2 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. 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 Corp. In 2013, 1.1 million 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.
Pinnacle.
The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. In 2013,
1.1 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. The metallurgical coal is then
shipped via railroad and barge to both domestic and export customers.
9
Pardee.
The Pardee property is located in Letcher County, Kentucky and Wise County, Virginia. In 2013,
758,000 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 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. During 2013, only a limited amount of production was shipped to utility
customers.
The map below shows the location of our properties in Central Appalachia.
10
Southern Appalachia
Oak Grove.
The Oak Grove property is located in Jefferson County, Alabama. In 2013, 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 2013, 1.8 million tons
were produced from these properties. We lease these properties to a number of operators including Appolo Fuels
Inc., Bell County Coal Corporation 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.
11
Illinois Basin
Williamson.
The Williamson property is located in Franklin and Williamson Counties, Illinois. The
property is under lease to an affiliate of Foresight Energy, and in 2013, 6.2 million tons were mined on the
property. This production is from a longwall mine. Production 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 an affiliate of Foresight Energy, and in 2013, 5.3 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
an affiliate of Foresight Energy, and in 2013, 927,000 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.
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 an affiliate of Foresight
Energy. See “— Transportation and Processing Assets.”
12
The map below shows the location of our properties in the Illinois Basin.
13
Northern Powder River Basin
Western Energy.
The Western Energy property is located in Rosebud and Treasure Counties, Montana. In
2013, 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.
14
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. These facilities generated $5.0 million in processing revenues for 2013.
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. For the year ended
December 31, 2013, we recognized $18.0 million in revenue from these assets. 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.
Aggregates and Industrial Minerals Properties
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 industrial building construction
and in most public works projects, such as roads, highways, bridges, railroad beds, dams, airports, water and
sewage treatment plants and systems and tunnels. 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.
In 2006, we bought our first aggregate property on the Puget Sound in Washington. Since that time, we have
made several other aggregate purchases in multiple U.S. geographies, and we are actively looking at additional
opportunities. We own and manage aggregate reserves, but we do not engage in the quarrying, processing or sale
of aggregate-related products. We own an estimated 500 million tons of aggregate reserves located in a number
of states across the country. During 2013, our lessees produced 6.2 million tons of aggregates, and aggregate
royalty revenues were $7.6 million.
Equity Interest in OCI Wyoming, L.P.
We own a 49% non-controlling equity interest in OCI Wyoming, L.P., an operator of a trona ore mining
operation and a soda ash refinery in the Green River Basin, Wyoming. We purchased the interest in OCI
Wyoming, L.P. in January 2013 for $292.5 million. Soda ash is used in the production of a variety of consumer
products, including glass, chemicals, soap and paper. All soda ash is sold through an OCI-affiliated sales agent to
various domestic and European customers and to American Natural Soda Ash Corporation for export. All mining
and refining activities take place in one facility located in the Green River Basin, Wyoming. In 2013, we have
received total distributions of $72.9 million from OCI Wyoming, including a $44.8 million special distribution
made in connection with certain restructuring and refinancing transactions in July 2013 in advance of the OCI
Resources LP initial public offering.
Oil and Natural Gas Properties
We generate oil and gas revenues from royalty, overriding royalty and non-operated working interests in
producing oil and gas wells. During 2013, we generated $17.1 million in revenues from our interests in oil and
gas properties. Our interests in oil and natural gas producing properties are in three primary regions: the
Appalachian Basin, the Williston Basin and the Mid-Continent region. NRP also owns interests in other oil and
gas properties in several states, including interests in properties located in northern Louisiana owned through
BRP LLC, a venture with International Paper in which NRP owns 51%. See “—BRP Properties.”
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
15
or delay rentals. 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. 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 wells, including the cost of
development and production.
We own royalty interests in approximately 261,000 net acres where we have leased certain portions of our
owned mineral interests to third parties. We own overriding royalty interests or non-operated working interests in
approximately 100,000 net acres. The overriding royalty interests are primarily located in Appalachian Basin in
West Virginia and Pennsylvania, including in the Marcellus Shale, and in the Haynesville Shale in Louisiana.
Producing Oil and Natural Gas Wells
The following tables set forth the gross and net producing oil and natural gas wells in which NRP held
working interests and royalty or overriding royalty interests as of December 31, 2013 by region. Gross wells
represent the number of wells in which NRP owns an interest. Net wells represent the total of our fractional
working interests or royalty interests, as applicable, owned in gross wells. NRP does not operate any wells.
Working Interest Wells
Oil
Natural Gas
Gross
Net
Gross
Net
Williston Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
218
18
—
—
As of December 2013, NRP also owned non-operated working interests in 40 gross oil wells in various
stages of development in the Williston Basin.
Royalty and Overriding Royalty
Interest Wells
Oil
Gross
Appalachian Basin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Continent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Williston Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Louisiana (BRP properties) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
40
25
12
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
107
Natural Gas
Gross
Net
711
6
—
274
991
71.3
0.7
—
7.4
79.4
Net
3.0
1.7
0.1
0.1
4.9
(1) 41 gross (1.3 net) natural gas wells are attributable to our overriding royalty interest in the Appalachian
Basin acquired in 2012. The remaining wells are primarily conventional oil and gas wells or coal bed
methane located in the southern portion of the Appalachian Basin.
Acreage Summary
The following table sets forth the gross and net mineral acres owned by NRP and leased to third parties as of
December 31, 2013 by region.
Appalachian Basin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Continent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Louisiana (BRP properties) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
202,772
13,061
63,661
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
279,494
199,718
11,211
50,216
261,145
NRP Fee Mineral Acres
Under Lease to Third Parties
Gross
Net
16
(1) The majority of our Appalachian Basin fee mineral acreage consists of coal bed methane and oil and gas
rights in properties located in the southern portion of the basin.
The following table contains a summary of the gross and net acres leased from third parties to NRP or in
which NRP had an overriding royalty interest as of December 31, 2013:
Appalachian Basin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Williston Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Louisiana (BRP properties)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acres Leased to NRP or ORRI
Gross
83,159
82,478
29,000
Net
55,284
15,746
29,000
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
194,637
100,030
(1) Consists of overriding royalty interests 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.
(2) Consists of a 1% overriding royalty interest.
BRP Properties
BRP is a venture between NRP and International Paper Company, of which NRP owns a 51% interest. As of
December 31, 2013, BRP had acquired, in several stages from International Paper, approximately 10 million
mineral acres in 31 states. While the vast majority of the 10 million acres remain largely undeveloped and
underexplored, BRP currently holds 59 revenue generating mineral leases and 17 cell tower leases. In addition, a
significant number of mineral prospects and deposits with yet undetermined commercial potential have been
identified through a variety of efforts including exploration drilling, coring, drill logs, electric logs, inferences
derived from published information, geological reports, geological maps, in-house efforts and consulting
investigations. These prospects and deposits are not necessarily near-term commercial opportunities due to a
variety of factors such as location, market, economic and production uncertainties, but have long-term
development potential.
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 under 41 leases as of December 31, 2013. In addition to the leased mineral
acreage, BRP holds a 1% gross production royalty interest on approximately 29,000 mineral acres in Louisiana.
The remaining oil and gas mineral acreage in Louisiana is not leased but a number of acres are in areas with
development potential. BRP has over 500 acres leased in Pennsylvania and approximately 300 acres leased in
Texas.
As of December 31, 2013, BRP owned nearly 95,000 net mineral acres of coal rights (primarily lignite) in
the Gulf Coast region, of which approximately 5,000 acres are leased under four separate leases in Louisiana and
Alabama. In addition to the coal rights, BRP has aggregate reserves (including limestone, granite, clay, and sand
and gravel) under lease in six states.
BRP also owns copper rights in Michigan’s Upper Peninsula that are subject to a development agreement
with Highland Copper Company Inc. By the end of 2013, Highland had drilled approximately 230 core holes
representing approximately 115,000 total feet that have been cored, sampled and analyzed for copper. Highland
expects to complete a feasibility study on the reserves in 2014.
Other mineral rights held by BRP as of December 31, 2013 included coalbed methane rights in four Gulf
Coast states, metal prospect rights in four states, approximately 450,000 acres of water and water royalty rights in
East Texas, geothermal rights and geothermal royalty interests in the Gulf Coast and Pacific Northwest, and
carbon sequestration rights primarily in the Gulf Coast region.
17
The map below illustrates the location of BRP’s current mineral rights.
18
Significant Customers
In 2013, we had total revenues of $88.4 million from Foresight Energy and its affiliated companies and
$55.1 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 13% of our revenue in 2013,
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 other 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. The industry has recently undergone
significant consolidation. This consolidation has led to a number of our lessees’ parent companies having
significantly larger financial and operating resources than their competitors. Our 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.
OCI Wyoming, which operates a trona mine and soda ash refinery 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 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
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 aggregate reserves in fee as of December 31, 2013. We lease
the remainder from unaffiliated third parties. As of December 31, 2013, 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.
19
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. Our lessees are obligated to conduct mining operations 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 mining operations are
not unusual and, notwithstanding compliance efforts, we do not believe violations by our lessees 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. We do not currently expect that future compliance will have a
material effect on us.
While it is not possible to quantify the costs of compliance by our lessees with all applicable federal, state
and local laws and regulations, those costs have been and are expected to continue to be significant. The lessees
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 coal, is subject to extensive
regulation regarding the environmental impact of its power generation activities, which could affect demand for
coal mined by our lessees. The possibility exists that new legislation or regulations could be adopted that have a
significant 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 substantial costs that could impact us.
Many of the statutes discussed below also apply to exploration and development activities associated with
our oil and natural gas investments and to the aggregates and industrial mineral mining operations in which we
hold interests, and therefore we do not present a separate discussion of statutes related to those activities.
Air Emissions. The Federal 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. Installation of additional emissions control technologies and other measures
required under U.S. Environmental Protection Agency (EPA) regulations 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. Any reduction in coal’s share of power generating capacity
could negatively impact our lessees’ ability to sell coal, which would have a material effect on our coal royalty
revenues.
20
In March 2005, the EPA issued a final Clean Air Interstate Rule (CAIR), which caps nitrogen oxide and
sulfur dioxide emissions in 28 eastern states and Washington, D.C. Since a majority of controls required by the
CAIR have been installed, we believe that the financial impact of the CAIR on coal markets has been factored
into the price of coal nationally and that its impact on demand has largely been taken into account by the
marketplace. However, in response to a remand of CAIR by the Court of Appeals for the D.C. Circuit on July 11,
2008, the EPA on August 8, 2011 adopted a replacement program, called the Cross-State Air Pollution Rule
(CSAPR), which is both broader in its geographic coverage and deeper in emission reductions than required by
CAIR. The CSAPR, in turn, was vacated by opinion of the D.C. Circuit on August 21, 2012. The U.S. Supreme
Court presently is considering EPA’s appeal of that decision, having heard oral argument on it in December
2013. Unless and until the Court reverses the D.C. Circuit’s vacatur of CSAPR, that rule remains unenforceable,
but all state regulations that were based on the CAIR are still in effect. We are unable to predict whether ongoing
judicial review proceedings may reinstate CSAPR or what rules EPA may propose in the event that the vacatur is
upheld, and, therefore, unable to predict any effect on NRP.
In June 2005, EPA announced final amendments to its regional haze program originally developed in 1999
to improve visibility in national parks and wilderness areas. Under the Regional Haze Rule, affected states were
to have developed implementation plans by December 17, 2007, that, among other things, identify facilities that
will have to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to
submit their plans by December 17, 2007, and the EPA issued a Finding of Failure to Submit plans on
January 15, 2009. On May 30, 2012, the EPA Administrator signed a final rule under which the emission caps
imposed under the CSAPR for a given state would supplant the obligations of that state with regard to visibility
protection. EPA’s plans to revisit this rule in light of the vacatur of the CSAPR have yet to be announced.
In February 2012, EPA published the Mercury and Air Toxics Rule (MATS), which imposes limits on the
hazardous air pollutant emissions allowed for the nation’s existing and future coal-fueled generation
fleet. Certain requirements of the MATS rule will become effective in 2015. These restrictions have contributed
and will continue to contribute to coal-fired power plant retirements. In response to legal challenges, EPA in
April 2013 published revisions to the standards for new units to make them more achievable. Legal challenges to
the remaining suite of MATS rules remain pending with the D.C. Circuit, which heard oral argument in
December 2013. The limits imposed by those rules may result in additional coal plant retirements or limit
demand for or otherwise restrict sales of our lessees’ coal, which would reduce our coal-related revenues.
Other continued tightening of the already stringent regulation of emissions is likely, such as the EPA’s
revision to the national ambient air quality standard for sulfur dioxide finalized in June 2010. As a result of these
and other tightening of ambient air quality standards, some states will be required to amend their existing state
implementation plans to attain and maintain compliance with the new air quality standards. These plan revisions
may call for significant additional emission control at coal-fired power plants.
The U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against a number of utilities with
coal-fired electric generating facilities alleging violations of the new source review provisions of the Clean Air
Act. The EPA has alleged that certain modifications have been made to these facilities without first obtaining
permits issued under the new source review program. Several of these lawsuits have settled, but others remain
pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected, which could
have an adverse effect on our coal royalty revenues.
Carbon Dioxide and Greenhouse Gas Emissions. In December 2009, the EPA determined that emissions of
carbon dioxide, methane, and other greenhouse gases (GHGs), present an endangerment to public health and
welfare because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s
atmosphere and other climatic changes. Legal challenges to these findings have been rejected by the D.C. Circuit
Court of Appeals, and the Supreme Court declined to review the intermediate appellate court’s rulings with
respect to the endangerment finding. Based on its findings, EPA has begun adopting and implementing
regulations to restrict emissions of GHGs under various provisions of the Clean Air Act. Shortly after issuing its
finding, EPA adopted rules regulating GHG emissions from motor vehicles, and other rules requiring permits for
emissions of GHGs from many stationary sources, including coal-fired electric power plants, effective January 2,
21
2011. As a result of revisions to its preconstruction permitting rules, EPA is now requiring new sources,
including coal-fired power plants, to undergo control technology reviews for GHGs (predominately carbon
dioxide) as a condition of permit issuance. These reviews may impose limits on GHG emissions, or otherwise be
used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for —
and so discourage development of — coal-fired power plants. The U.S. Supreme Court presently is considering
the legality of those rules, which were upheld by the D.C. Circuit Court of Appeals.
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, beginning in 2011 for
emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an
annual basis, beginning in 2012 for emissions occurring in 2011.
On January 8, 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. President Obama has directed EPA to issue proposed regulations on existing fossil fuel-
fired power plants in June 2014. We expect that EPA’s proposed regulations for both new and existing power
plants will negatively affect the viability of coal-fired power generation, which will ultimately reduce coal
consumption and the production of coal from our properties.
Several states have also either passed legislation or announced initiatives focused on decreasing or
stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures
have focused on emissions from coal-fired electric generating facilities. Other regional programs are being
considered in several regions of the country. It is possible that future federal and state initiatives to control
carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to
install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to
comply with future emissions trading programs. Such increased costs for coal consumption could result in some
customers switching to alternative sources of fuel, which could negatively impact our lessees’ coal sales, and
thereby have an adverse effect on our coal royalty revenues.
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. In conjunction with mining the property, 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.
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. These persons include the owner or operator of the site
where the release occurred, and companies that improperly stored or disposed or arranged for the disposal of the
hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances
that have been released into the environment and for damages to natural resources.
Products such as explosives used by coal companies in operations generate waste containing hazardous
substances. We could become liable under federal and state Superfund and waste management statutes if our
lessees are unable to pay environmental cleanup costs. CERCLA authorizes the EPA and, in some cases, third
parties, to take actions in response to threats to the public health or the environment, and to seek recovery from
22
the responsible classes of persons of the costs they incurred in connection with such response. It is not
uncommon for neighboring landowners and other third parties to file claims for personal injury and property
damage allegedly caused by hazardous substances or other wastes released into the environment.
In June 2010, EPA released a proposed rule to regulate the disposal of certain Coal Combustion Residuals
(CCR), often referred to as coal ash, from electric utilities. The proposed rule sets forth two proposed avenues for
the regulation of CCR under the Resource Conservation and Recovery Act (RCRA). The first option calls for
regulation of CCR under Subtitle C as a hazardous waste, which creates a comprehensive program of federally
enforceable requirements for waste management and disposal. The second option calls for regulation of CCR
under Subtitle D as a solid waste, which gives EPA authority to set performance standards for solid waste
management facilities and would be enforced primarily through state agencies and citizen suits. Under both
options, EPA would establish dam safety requirements to address structural integrity of surface impoundments to
prevent catastrophic releases. The proposal leaves intact the exemption for beneficial uses of CCR, except for
land application. In April 2012, several environmental organizations filed suit against EPA to compel EPA to
take action on the proposed rule. EPA conducted additional information collections in August 2013; however, by
year-end 2013, EPA had not finalized CCR rules nor established a timeline for finalization. In a consent decree
filed on January 29, 2014, EPA has agreed to take final action by December 19, 2014. Although EPA has
indicated that coal ash use may be appropriate under certain circumstances, if CCR were re-classified as
hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities,
require groundwater testing and impose restrictions on storage locations, which could increase our lessees’
operating costs and potentially reduce their ability to produce coal, which could affect our coal royalty revenues.
In addition, contamination caused by the past disposal of CCR, including coal ash, can lead to material liability
to our lessees under RCRA or other federal or state laws and potentially reduces the demand for coal.
Water Discharges. Our lessees’ operations can result in discharges of pollutants into waters. The Clean
Water Act and analogous state laws and regulations create two permitting programs for our lessees. The National
Pollutant Discharge Elimination System (NPDES) program under Section 402 of the statute is administered by
the states or the 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 the 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.
Our lessees generally obtain “individual” permits from the Corps of Engineers authorizing the construction
of valley fills for the disposal of overburden from mining operations. The application process for acquiring
individual permits has become more cumbersome and can require the preparation of an environmental impact
statement as part of the application. Small underground coal mines that must construct fills, limited by acreage
and length, as part of their mining operations may qualify for another version of the Section 404 permit known as
“nationwide permit 50.” Both individual and nationwide permits are subject to challenge in citizens’ lawsuits.
Such challenges result in delays in our lessees obtaining the required mining permits to conduct their operations,
which could, in turn, have an adverse effect on our coal-related revenues.
Beginning in 2009, the EPA put in place a series of policies for mines in Central Appalachia that have had
the effect of slowing the issuance of both Section 404 fill permits by the Corps and Section 402 NPDES permits
by state agencies. These policies, among other things, seek to impose limits on specific conductance
(conductivity) and sulfate at levels that can be unachievable absent treatment at many mines. The technologies
available to treat conductivity and/or sulfate are expensive and may be impracticable at all but the largest
underground mines. These policies are subject to challenge in federal district court in Washington, D.C. in
National Mining Association v. Jackson. In two separate opinions, the district court rejected the EPA’s process
for reviewing state-issued Section 402 permits and determined that the EPA’s policies constituted unlawful
23
rulemaking for conductivity and fell outside of the EPA’s statutory authority. The EPA has appealed the final
July 2012 decision.
In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits
against operators and landowners. In 2012 and 2013, several citizen suit group lawsuits were 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 seek penalties
as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate. While it is too
early to determine the ultimate resolution of these lawsuits, any rulings requiring operators to reduce their
discharges of selenium, conductivity or sulfate could result in large treatment expenses for our lessees. In 2013,
several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including
selenium, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case,
the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond
has been released. 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
would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.
The Clean Water Act also requires states to develop anti-degradation policies to ensure non-impaired water
bodies in the state do not fall below applicable water quality standards. These and other regulatory developments
may 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 royalty revenues.
In addition, Section 316(b) of the Clean Water Act requires that the location, design, construction and
capacity of cooling water intake structures reflect the best technology available for minimizing adverse
environmental impact. EPA promulgated rules for cooling water intake structures in three phases: Phase I for
new facilities, Phase II for large existing electric generating plants, and Phase III for certain existing facilities and
new offshore and coastal oil and gas extraction facilities. The Phase II rules were suspended in March 2007 in
response to the Second Circuit decision in Riverkeeper v. EPA. EPA signed a settlement agreement with
Riverkeeper on the rulemaking dates in 2010 and published proposed rules in April 2011. EPA has since
published two notices of data availability summarizing the data received and collected since publishing the
proposed rule. EPA and Riverkeeper have also agreed to modify the settlement agreement to give EPA additional
time to finalize the new rule.
The Federal Safe Drinking Water Act (SDWA) and its state equivalents affect coal mining operations by
imposing requirements on the underground injection of fine coal slurries, fly ash and flue gas scrubber sludge,
and by requiring permits to conduct such underground injection activities. In addition to establishing the
underground injection control program, the SDWA also imposes regulatory requirements on owners and
operators of “public water systems.” This regulatory program could impact our lessees’ reclamation operations
where subsidence or other mining-related problems require the provision of drinking water to affected adjacent
homeowners.
Mine Health and Safety Laws. The operations of our lessees 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
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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 (“POV”) program, if a mine’s rate of injuries or significant and substantial citations exceed
a certain threshold. A mine that is placed in a POV program will receive additional scrutiny from MSHA.
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
the 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. The OSM has subsequently undertaken efforts to
vacate the 2008 revision and to promulgate a new rule that could prohibit the placement of valley fills in streams.
While it is too early to predict the outcome of these efforts, any regulatory change 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 the 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 results in the EPA’s ability to veto a fill permit
whenever it determines that an adverse effect will result, even if such determination is made years after the
permit has been issued. 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 the EPA that is adverse to the mining industry. Mingo Logan filed a petition for certiorari
seeking a review of the decision by the United States Supreme Court of Appeals, but there has not yet been a
ruling on that petition.
Over the past year, the industry has successfully challenged EPA policy, regulations and guidance in several
other court decisions, including National Mining Association v. Jackson and EME Homer City Generation, L.P.
v. EPA. While each of these cases has unique facts and circumstances, the general theme in these cases is that the
EPA has overreached its authority in a number of instances. However, the EPA has continued to promulgate
regulations that will negatively affect the viability of coal-fired generation, which will ultimately reduce coal
consumption and the production of coal from our properties. Additionally, citizens’ groups have continued to be
active in bringing lawsuits against operators, as well as challenging permits issued by the Army Corps of
Engineers. In May 2013, in Ohio Valley Environmental Coalition Inc. v. U.S. Army Corps of Engineers, a panel
of the U.S. Court of Appeals for the Fourth Circuit upheld a previously issued Section 404 permit following a
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challenge by a coalition of environmental groups that the U.S. Army Corps of Engineers had failed to consider
the full environmental impact of the proposed mine. Affirming the U.S. District Court’s decision, the Fourth
Circuit panel held that the Army Corps had issued the permit after conducting appropriate analysis of the
potential environmental impact of the proposed mine. While other similar suits are pending or may be brought,
this decision is an important development for the industry against citizen suit challenges of previously issued
permits.
Federal and state surface mining laws require mine operators to post reclamation bonds to guarantee the
costs of mine reclamation. West Virginia’s bonding system requires coal companies to post site-specific bonds in
an amount up to $5,000 per acre and imposes a per-ton tax on mined coal currently set at $0.279/ton, which is
paid to the West Virginia Special Reclamation Fund (SRF). The site-specific bonds are used to reclaim the
mining operations of companies that default on their obligations under the West Virginia Surface Coal Mining
and Reclamation Act. The SRF is used where the site-specific bonds are insufficient to accomplish reclamation.
Employees and Labor Relations
We do not have any employees. To carry out our operations, affiliates of our general partner employ
approximately 80 people who directly support our 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 revenue from these natural resource properties are royalties from coal, aggregates, oil
and gas, timber, related transportation and processing infrastructure revenues, as well as our equity investment in
OCI Wyoming’s trona mine and soda ash refinery operations.
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
Coal prices have declined substantially in recent years, which has negatively affected our coal-related
revenues and the value of our 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 reserves.
Prices for both steam and metallurgical coal have declined substantially in recent years. 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;
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• the price and availability of alternative fuels, especially natural gas;
• 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. Natural gas prices
remained relatively low during 2013, and a number of utilities have switched generation 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. In addition, prices for
metallurgical coal hit multi-year lows in 2013 despite increased global demand for steel. 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. 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.
Our coal lessees’ mining operations are subject to operating risks that could result in lower coal-related
revenues to us.
Aside from pricing risk, the most significant risk faced by coal lessees that impacts NRP is permitting. As a
result of recent judicial decisions and the increased involvement of the Administration and the 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 NRP might
otherwise be involved.
Our royalty revenues are largely dependent on our lessees’ level of production from our mineral reserves,
and any interruptions to the production of coal from our reserves would reduce our coal-related revenues. The
level of our lessees’ production is subject to operating conditions or events beyond their or our 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;
• the price of natural gas, which is a competing fuel in the generation of electricity;
• changes in governmental regulation and policy related to the coal industry or the electric utility industry;
• mining and processing equipment failures and unexpected maintenance problems;
• interruptions due to transportation delays;
• adverse weather and natural disasters, such as heavy rains and flooding;
• labor-related interruptions; and
• fires and explosions.
Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to
persons arising from their operations. If our lessees are pursued for these sanctions, costs and liabilities, their
mining operations and, as a result, our royalty revenues and other coal-related revenues could be adversely
affected.
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A sustained reduction or further decrease in the demand for metallurgical coal could result in lower coal
production by our lessees, which would reduce our coal-related revenues.
Our lessees produce a significant amount of the metallurgical coal that is used in both the U.S. and foreign
steel industries. In 2013, approximately 31% of the coal production and 41% of the coal royalty revenues from
our properties were from metallurgical coal. The first quarter 2014 benchmark price for metallurgical coal is at a
multi-year low of $143 per metric ton. 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. Global production of steel continues to outpace demand. In
addition, rising exports of metallurgical coal from Australia 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.
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 new power plants will be built to produce electricity. Most of these
new power plants will be fired by natural gas because of lower construction costs compared to coal-fired plants
and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of 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 power plants are expected to further limit the construction of new coal-
fired generation plants in favor of alternative sources of energy. We expect that EPA’s proposed regulations for
both new and existing power plants will 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” could
result in reduced demand for our coal.
In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other greenhouse
gases, or “GHGs,” present an endangerment to public health and welfare because emissions of such gases are,
according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Legal
challenges to these findings have been rejected by the D.C. Circuit Court of Appeals, and the Supreme Court
declined to review the intermediate appellate court’s rulings with respect to the endangerment finding. Based on
its findings, EPA has begun adopting and implementing regulations to restrict emissions of GHGs under various
provisions of the Clean Air Act. Shortly after issuing its finding, EPA adopted rules regulating GHG emissions
from motor vehicles, and other rules requiring permits for emissions of GHGs from many stationary sources,
including coal-fired electric power plants, effective January 2, 2011. As a result of revisions to its
preconstruction permitting rules, EPA is now requiring new sources, including coal-fired power plants, to
undergo control technology reviews for GHGs (predominately carbon dioxide) as a condition of permit issuance.
These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative
fuels and generation systems, as well as increase litigation risk for — and so discourage development of — coal-
fired power plants. The U.S. Supreme Court presently is considering the legality of those rules, which were
upheld by the D.C. Circuit Court of Appeals.
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, beginning in 2011 for
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emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an
annual basis, beginning in 2012 for emissions occurring in 2011.
On January 8, 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. President Obama has directed EPA to issue proposed regulations on existing fossil fuel-
fired power plants in June 2014. We expect that EPA’s proposed regulations for both new and existing power
plants will negatively affect the viability of coal-fired power generation, which will ultimately reduce coal
consumption and the production of coal from our properties.
Several states have also either passed legislation or announced initiatives focused on decreasing or
stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures
have focused on emissions from coal-fired electric generating facilities. Other regional programs are being
considered in several regions of the country. It is possible that future federal and state initiatives to control
carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to
install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to
comply with future emissions trading programs. Such increased costs for coal consumption could result in some
customers switching to alternative sources of fuel, which could negatively impact our lessees’ coal sales, and
thereby have an adverse effect on our coal royalty revenues.
In addition to the climate change legislation, our lessees are subject to numerous other federal, state and
local laws and regulations that may limit their ability to produce and sell minerals from our properties. In
addition, our oil and gas operations are also subject to numerous laws and regulations.
Our lessees may incur substantial costs and liabilities under increasingly strict federal, state and local
environmental, health and safety laws, including regulations and governmental enforcement policies. The oil and
gas and soda ash production operations in which we hold interests are 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 or our lessees’ operations.
In February 2012, EPA published the MATS rule, which imposes limits on the hazardous air pollutant
emissions allowed for the nation’s existing and future coal-fueled generation fleet. Certain requirements of the
MATS rule will become effective in 2015. These restrictions have contributed and will continue to contribute to
coal-fired power plant retirements, including causing some existing plants that would otherwise be able to
continue operations but for the requirements of the MATS rule to announce closures. Legal challenges to some
portions of the MATS rules are pending with the D.C. Circuit. When determined, the limits imposed by those
rules may result in additional coal plant retirements or limit demand for or otherwise restrict sales of our lessees’
coal, which would reduce our coal-related revenues.
New environmental legislation, new regulations and new interpretations of existing environmental laws,
including regulations governing permitting requirements, could further regulate or tax the mineral 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.
As a result of ongoing consolidation in the coal industry and our partnership with Foresight Energy, we
derive a large percentage of our revenues from a small number of coal lessees.
In 2013, we derived 25% of our revenues from Foresight Energy and its affiliated companies and 15% from
Alpha Natural Resources. Foresight’s Williamson mine alone was responsible for approximately 13% of our
revenues in 2013. As a result, we have significant concentration of revenues with those lessees, although in most
cases, with the exception of Williamson, the exposure is spread out over a number of different mining operations
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and leases. 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 royalty revenues and ability to make future
distributions would be adversely affected.
Prices for soda ash, crude oil and natural gas are volatile. Any substantial or extended decline in soda ash
or crude oil and natural gas 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. 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. The prices OCI Wyoming receives for its soda ash and the prices we receive with respect to our
interests in oil and gas producing assets depend on numerous factors beyond our control, including worldwide
and regional economic and political conditions impacting supply and demand. Substantial or extended declines in
prices for these commodities 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.
Our business will be adversely affected if we are unable to make acquisitions or access the capital markets
to finance our growth.
Because our reserves decline as our lessees mine our minerals, our future success and growth depend, in
part, upon our ability to make acquisitions, including mineral reserve acquisitions to replace reserves that are
mined. If we are unable to make acquisitions on acceptable terms, our revenues will decline as our reserves are
depleted. Our ability to acquire additional mineral reserves or make other acquisitions is dependent in part on our
ability to access the 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.
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;
• future crude oil and natural gas prices and their differentials;
• future development costs, operating costs and property taxes; and
• potential environmental and other liabilities.
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
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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 liabilities and acquire properties on an “as is” basis.
If our lessees do not manage their operations well, their production volumes and our royalty revenues could
decrease.
We depend on our lessees to effectively manage their operations on our properties. Our lessees make their
own business decisions with respect to their operations within the constraints of their leases, including decisions
relating to:
• the payment of minimum royalties;
• marketing of the minerals mined;
• mine plans, including the amount to be mined and the method of mining;
• processing and blending minerals;
• expansion plans and capital expenditures;
• credit risk of their customers;
• permitting;
• insurance and surety bonding;
• acquisition of surface rights and other mineral estates;
• employee wages;
• transportation arrangements;
• compliance with applicable laws, including environmental laws; and
• mine closure and reclamation.
A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments,
could give us the right to terminate the lease, repossess the property and enforce payment obligations under the
lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find
a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a
reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could
further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter
into a new lease, the replacement operator might not achieve the same levels of production or sell minerals at the
same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for
small or isolated mineral reserves, since industry trends toward consolidation favor larger-scale, higher-
technology mining operations in order to increase productivity.
Our investments in operating businesses expose us to risks that we do not experience in the royalty business.
In addition, we have limited control over the activities on properties that we do not operate.
Our 49% interest in the trona mining and soda ash refining operations of OCI Wyoming and our ownership
of non-operated working interests in oil and gas properties subject us to operational and other contingent
liabilities to which we are not exposed through our ownership of mineral rights and royalties. Further, we only
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
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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. We have capital expenditures and operating expenses associated with the wells in which we
own interests and are required to fund our proportionate share on any wells that we decide to participate in. 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. 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 the Williamson mine, and have assumed the capital and operating
risks associated with that business. As a result of these investments, we could experience increased costs as well
as increased liability exposure associated with operating these facilities.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the
production of coal, oil and gas and other minerals from our properties.
Transportation costs represent a significant portion of the total delivered cost for the customers of our
lessees. Increases in transportation costs could make coal a less competitive source of energy or could make
minerals produced by some or all of our lessees less competitive than coal produced from other sources. On the
other hand, significant decreases in transportation costs could result in increased competition for our lessees from
producers in other parts of the country.
Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals to their customers.
Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes,
lockouts, bottlenecks and other events could temporarily impair the ability of our lessees to supply minerals to
their customers. Our lessees’ transportation providers may 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, OCI Wyoming ships substantially
all of its soda ash on a single rail line under one contract with the Union Pacific Railroad Company that expires
during 2014. There can be no assurance that the contract will be renewed on terms favorable to OCI Wyoming or
at all. Any substantial decrease in the prices OCI Wyoming receives for its soda ash or an interruption in the
transportation of its 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. Recent 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.
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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, 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.
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.
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. 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.
Our reserve estimates depend on many assumptions that may be inaccurate, which could materially
adversely affect the quantities and value of our reserves.
Our reserve estimates may vary substantially from the actual amounts of minerals our lessees may be able to
economically recover 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
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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;
• future mining technology improvements;
• the effects of regulation by governmental agencies; and
• geologic and mining conditions, which may not be fully identified by available exploration data and may
differ from our experiences in areas where our lessees currently mine.
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.
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 Inherent in an Investment in Natural Resource Partners L.P.
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. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and
working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash
distributions might be made during periods when we record losses and might not be made during periods when
we record profits In January 2014, our board of directors declared a cash distribution of $0.35 with respect to the
fourth quarter of 2013, representing a 36% decrease from the distribution level paid with respect to the third
quarter of 2014. Additional decreases in the quarterly distribution may occur to the extent our board of directors
determines appropriate.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations
and business prospects.
As of December 31, 2013, we and our subsidiaries had approximately $1.17 billion of total indebtedness.
The terms and conditions governing our indebtedness, including NRP’s 9 1⁄ 8% senior notes, Opco’s revolving
credit facility, term loan and senior notes, and NRP Oil and Gas’s revolving credit facility:
• 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 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;
34
• 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, sell assets, borrow
more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise
equity on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive covenants
in our debt agreements will be affected by the levels of cash flow from our operations and future events and
circumstances beyond our control. Failure to comply with these covenants would result in an event of default
under our indebtedness, and such an event of default could adversely affect our business, financial condition and
results of operations.
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 will 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 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
• 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.
35
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.
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;
• 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;
36
• 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 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
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.
37
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
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.
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
38
receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not
representing gain, may be taxed as ordinary income due to potential recapture items, including depletion and
depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse
liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you
receive from the sale.
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. Nonetheless, we allocate certain deductions for
depreciation of capital additions based upon the date the underlying property is placed into service. The use of
this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department
has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded
partnership may use a similar monthly simplifying convention to allocate tax items among transferor and
transferee unitholders. Nonetheless, the proposed regulations 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
39
purposes as a partner with respect to those common units during the period of the loan and the unitholder may
recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain,
loss or deduction with respect to those common units may not be reportable by the unitholder and any cash
distributions received by the unitholder as to those common units could be fully taxable as ordinary income.
Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their
common units are urged to modify any applicable brokerage account agreements to prohibit their brokers from
borrowing their common units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period
will result in the termination of us as a partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale
or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For
purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be
counted only once. 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.
40
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties.
The information required by this Item is included under Item 1, “Business” and 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
Not applicable.
41
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of
Equity Securities
Our common units are listed and traded on the NYSE under the symbol “NRP”. As of February 20, 2014,
there were approximately 42,000 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 3, 2012 to December 31, 2013, 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
2012
First Quarter . . . . . . . . . . . . . . . . . . . . . .
Second Quarter
. . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . .
2013
First Quarter . . . . . . . . . . . . . . . . . . . . . .
Second Quarter
. . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . .
$28.70
$25.08
$23.04
$22.50
$23.95
$24.37
$22.39
$21.57
$23.36
$21.45
$18.67
$16.90
$18.93
$20.08
$18.98
$18.99
$0.5500
$0.5500
$0.5500
$0.5500
$0.5500
$0.5500
$0.5500
$0.3500
05/04/2012
08/03/2012
11/05/2012
02/05/2013
05/14/2012
08/14/2012
11/14/2012
02/14/2013
05/06/2013
08/05/2013
11/05/2013
01/21/2014
05/14/2013
08/14/2013
11/14/2013
01/31/2014
2012 Distributions
2013 Distributions
Cash Distributions to Partners
(In thousands)
General
Partner
Limited
Partners
Total
Distributions
$4,758 $233,263
$4,930 $241,587
$238,021
$246,518
42
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 Forms 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.
(In thousands, except per unit data)
For the Years Ended December 31,
2013
2012
2011
2010
2009
Total revenues and other income . . . . . . . . . $ 358,117 $ 379,147
Asset impairments . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic and diluted net income per limited
$
$ 236,236 $ 267,165
$ 172,078 $ 213,355
$ 377,683
2,568 $ 161,336
$ 104,135
54,026
$
734
$
— $
$ 301,401
$
$ 196,061
$ 154,461
$ 256,084
—
$ 153,975
$ 114,080
partner unit
. . . . . . . . . . . . . . . . . . . . . . . .
Distributions paid ($ per unit) . . . . . . . . . . . .
Weighted average number of common units
outstanding . . . . . . . . . . . . . . . . . . . . . . . .
Cash from operations . . . . . . . . . . . . . . . . . .
Distributable Cash Flow(1) . . . . . . . . . . . . . .
EBITDA(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance sheet data:
Cash and cash equivalents . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
Long-term debt
Partners’ capital . . . . . . . . . . . . . . . . . . . . . . .
$
$
1.54
2.20
$
$
1.97
2.20
$
$
0.50
2.17
$
$
1.54
2.16
$
$
1.17
2.16
109,584
106,028
$ 247,074 $ 271,408
$ 309,394 $ 298,899
$ 316,657 $ 328,116
106,028
$ 305,574
$ 311,174
$ 329,660
81,917
$ 258,694
$ 260,274
$ 253,074
67,702
$ 210,669
$ 210,669
$ 214,200
92,513 $ 149,424
$
82,634
$ 214,922
$1,991,856 $1,764,672 $1,665,649 $1,664,036 $1,523,590
$ 626,587
$ 836,268
$1,084,226 $ 897,039
$ 765,226
$ 644,915
$ 616,789 $ 617,447
$ 661,070
$ 825,180
95,506
$
$
(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 at a level that can sustain or support an increase in quarterly cash distributions paid 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, distributions from unconsolidated
investments, proceeds from sale of assets and returns on direct financing lease and contractual override.
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.
43
Prior to 2013, we reduced our distributable cash flow by the amount of cash we had reserved for principal
payments due on our senior notes in the next calendar year. However, to present our distributable cash flow more
in line with MLP practice, we no longer reduce distributable cash flow by reserves for future principal payments.
We have changed our 2009, 2010, 2011 and 2012 calculations in the table below to be comparable with our
presentation for 2013. This change in our reporting of distributable cash flow does not change our long-term
intention to reduce our debt.
Reconciliation of “Net cash provided by operating activities” to “Distributable cash flow”
Year Ended December 31,
2013
2012
2011
2010
2009
Net cash provided by operating activities . . . . . . . . . .
Distributions from unconsolidated investments(1) . . .
Return on direct financing lease and contractual
override . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of assets . . . . . . . . . . . . . . . . . . . . .
(in thousands)
$247,074 $271,408 $305,574 $258,694 $210,669
—
48,833
—
—
—
2,558
10,929
2,669
24,822
—
5,600
—
1,580
—
—
Distributable cash flow . . . . . . . . . . . . . . . . . . . . . . . . .
$309,394 $298,899 $311,174 $260,274 $210,669
(1) The cash distributions that NRP received from OCI Wyoming were $72.9 million for the year ended
December 31, 2013. The amount included in the table reflects the difference between the cash distributions
received and the other income we recorded from the OCI Wyoming investment, which are included in net
cash provided by operating activities.
EBITDA
EBITDA is a non-GAAP financial measure that we define as earnings before interest, taxes, depreciation,
depletion and amortization and asset impairment. 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. EBITDA should not be considered in isolation or as a substitute for operating income,
net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash
flow statement data prepared in accordance with GAAP. EBITDA provides no information regarding a
company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or
tax positions. 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 EBITDA is useful in evaluating our financial performance because this measure is
widely used by analysts and investors for comparative purposes. We have not previously included EBITDA as a
financial measure in our annual or quarterly reports. However, NRP entered the high-yield bond market in 2013,
and EBITDA is a financial measure widely used by investors in that market. There are significant limitations to
using EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and
non-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 EBITDA reported by different
companies.
44
Reconciliation of “Net income” to “EBITDA”
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add depreciation, depletion and amortization . . . . . . .
Add asset impairments . . . . . . . . . . . . . . . . . . . . . . . . .
Add interest expense, gross . . . . . . . . . . . . . . . . . . . . .
Add depreciation, depletion and amortization relating
to OCI Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2013
2012
2011
2010
2009
(in thousands)
$172,078 $213,355 $ 54,026
58,221
65,118
161,336
2,568
49,180
53,972
64,377
734
64,396
$154,461
56,978
—
41,635
$114,080
60,012
—
40,108
15,072
—
—
—
—
EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$316,657 $328,116 $329,660 $253,074 $214,200
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 “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.
45
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. For more detailed
information regarding the basis of presentation for the following financial information, see the Notes to the
Consolidated Financial Statements.
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
Our Business
We engage principally in the business of owning, managing and leasing mineral properties in the
United States. We own coal reserves 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. As of December 31,
2013, we owned or controlled approximately 2.3 billion tons of proven and probable coal reserves. We do not
operate any 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 for our company, particularly in the Illinois Basin.
We have made a concerted effort to diversify our business in recent years. In 2013, we spent over
$365 million to acquire interests in non-coal-related operating businesses. In January 2013, we acquired a non-
controlling equity interest in OCI Wyoming, L.P., an operator of a trona ore mining operation and a soda ash
refinery in the Green River Basin, Wyoming for $292.5 million. We also completed two acquisitions of non-
operated working interests in oil and gas operations in the Williston Basin of North Dakota and Montana for an
aggregate purchase price of $72 million. In addition, we own various interests in oil and gas properties that are
located in other areas, including the Appalachian Basin, Louisiana and Oklahoma, and we have acquired
approximately 500 million tons of aggregate reserves located in a number of states across the country.
For the year ended December 31, 2013, we recognized approximately $145.5 million (40.6%) of our
revenues and other income from sources other than coal royalties, which primarily consisted of equity income
from our investment in OCI Wyoming, oil and gas revenues, aggregates royalties, overriding royalties (which
include coal and aggregates overrides), minimums recognized as revenue, and processing and transportation fees.
The revenues that we recognize from minimums and processing/transportation are largely derived from coal-
related businesses.
In our coal and aggregate royalty business, our lessees generally make payments to us based on the greater
of a percentage of the gross sales price or a fixed royalty per ton of coal or aggregates they sell, subject to
minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a
specified period of time, which varies by lease, if sufficient royalties are generated from production in those
future periods. We do not recognize these minimum royalties as revenue until the applicable recoupment period
has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are
recorded as deferred revenue, a liability on our balance sheet.
Oil and gas royalty revenues include production payments as well as bonus payments. Oil and gas royalty
revenues 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. 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
46
capital expenditures and operating expenses associated with the non-operated working interests in oil and gas
assets.
Our Current Liquidity Position
In September 2013, NRP, together with NRP Finance as co-issuer, sold $300.0 million of 9.125% Senior
Notes due 2018 at an issue price of 99.007% of par value for net proceeds of $289 million. We used the net
proceeds of the offering to repay all outstanding borrowings under Opco’s revolving credit facility. Opco’s
revolving credit facility does not mature until August 2016 and, as of December 31, 2013, Opco had $280 million
in available capacity under the facility. In August 2013, NRP Oil and Gas entered into a senior secured, reserve-
based revolving credit facility with an initial $8.0 million borrowing base. During December 2013, the borrowing
base was increased to $16.0 million. As of December 31, 2013, NRP Oil and Gas had the full $16.0 million
available for borrowing under its revolving credit facility. As of the date of this filing, NRP Oil and Gas had
$2.0 million of borrowings outstanding under its credit facility. We typically access the capital markets to
refinance amounts outstanding under our revolving credit facilities as we approach the limits under those
facilities, the timing of which depends on the pace and size of our acquisition program and development capital
expenditures associated with our oil and gas business.
We refinanced a $35 million Opco senior note that matured in 2013, as well as $15 million of the remaining
$52 million in principal payments due on Opco’s senior notes during 2013. We have $81.0 million in principal
payments on Opco’s senior notes due in 2014. While we intend to reduce our leverage by paying the full amount
with cash from operations, we may refinance some or all of these obligations as they come due.
We used $91.0 million of net proceeds from the September 2013 senior notes offering to repay principal on
Opco’s term loan. We also used a portion of the proceeds from the July 2013 $44.8 million special distribution
from OCI Wyoming to repay $10.0 million of principal on Opco’s term loan. Opco’s next principal repayment
obligation on the term loan is in January 2016, when Opco will be required to repay the remaining principal
amount outstanding thereunder of $99.0 million.
In addition to the amounts available under our revolving credit facilities, we had $92.5 million in cash at
December 31, 2013. We believe that the combination of our capacity under our revolving credit facilities and our
cash on hand gives us enough liquidity to meet our current financial needs. Other than $81 million in principal
repayments due on Opco’s senior notes each year for the next several years, we do not have any debt maturing
until 2016. In January 2014, our Board of Directors declared a cash distribution of $0.35 per unit with respect to
the fourth quarter of 2013. The distribution represents a $0.20 (36%) decrease from the distribution declared and
paid with respect to the third quarter of 2013. We believe that the distribution decrease will save NRP
approximately $89.6 million annually and position NRP to reduce its debt over time while preserving its liquidity
to pursue accretive acquisitions.
Current Results/Market Outlook
Our total revenues and other income for 2013 were $358.1 million, which were down compared to the
$379.2 million in total revenues and other income received for 2012. Although our total revenues and other
income were down only 5.5% from 2012, our coal royalty revenues were down approximately 18.4% from 2012
and our Central Appalachian coal royalty revenues were down approximately 32.9% from 2012. We anticipated
these declines and continue to see the benefits of our diversification efforts, as our revenues and other income
from sources other than coal royalties represented over 40% of our total revenues and other income in 2013, up
from approximately 31% of total revenues and other income in 2012. We expect that coal royalties will represent
a lower percentage of total revenues and other income in 2014. As compared to 2012, our coal royalty revenues
from the Illinois Basin were up 13% in 2013, our investment in OCI Wyoming’s trona mining and soda ash
production operations contributed $34.2 million in other income, and our oil and gas revenues increased 86% and
continue to ramp up. Despite the decrease in our coal royalty revenues during 2013, our distributable cash flow
increased slightly over 2012, primarily due to the $72.9 million in distributions that we received from OCI during
2013.
47
Despite NRP’s solid operating and financial performance in 2013, the coal markets continue to be uncertain,
and prices for both steam and metallurgical coal continue to be severely depressed. We expect that the challenges
that have affected the coal markets over the last two years will continue through at least 2014. The outlook for
high-cost Central Appalachian steam coal is challenging due to federal government policy and regulations
combined with natural gas prices remaining at levels that are low enough to make Central Appalachian steam
coal production uneconomic. In addition, the Illinois Basin continues to increase production and is displacing
Central Appalachian coal at some utilities. We benefit from the Illinois Basin growth through our relationship
with Foresight Energy. As a result of the exceptionally cold winter of 2013-2014, natural gas prices have
increased substantially and natural gas storage levels have dropped below the five-year average. In addition,
utilities have been running their coal units, including those units expected to be retired in 2015, at near full
capacity, and coal stockpiles have been reduced below 2013 levels. The impact of the high natural gas prices and
cold weather on thermal coal prices has been muted so far, but utilities have entered 2014 with larger spot
positions than in the past, and the reduced stockpiles could force them to purchase coal on the spot market at
higher prices during the peak heating and cooling seasons in 2014.
We also continue to have substantial exposure to metallurgical coal, from which we derived approximately
41% of our coal royalty revenues and 31% of the related production during 2013. The first quarter 2014
benchmark price for metallurgical coal is at a multi-year low of $143 per metric ton. Although the global demand
for steel continues to increase, global production continues to outpace demand. In addition, rising exports of
metallurgical coal from Australia continue to have a negative effect on prices received for metallurgical coal
produced in the United States. Due to continued high global production levels and currently weak Australian and
Canadian dollars, we do not anticipate metallurgical coal prices recovering in 2014.
Lessees move on and off of our properties over the course of any given year in accordance with their mine
plans. Our revenues are reduced when a lessee’s mine plan results in the mining of reserves adjacent to our
properties that are not owned by us. These reductions are generally offset by other lessees moving their mining
operations back on to our properties. During the fourth quarter of 2013, we experienced a decline in coal
production due to several high-volume lessees conducting their mining operations on adjacent properties in
accordance with their mine plans. We expect that the volumes of coal produced by lessees moving off of our
properties for 2014 will exceed the volumes produced as lessees move back on our properties during 2014. These
reduced volumes, along with continued depressed coal prices, are expected to result in a significant decrease in
our coal royalty revenues during 2014 as compared to prior years. OCI Wyoming’s soda ash business has
performed as we projected during 2013, but the increased liquidity associated with a refinancing transaction
resulted in higher than expected cash distributions to NRP in 2013, including a $44.8 million special distribution
in July 2013. NRP anticipates receiving approximately $42.5 million of distributions from the OCI Wyoming
investment in 2014.
Political, Legal and Regulatory Environment
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. Furthermore, the federal courts have recently handed down several decisions that are adverse to
the coal industry. 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. On
January 8, 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.
President Obama has directed EPA to issue proposed regulations on existing fossil fuel-fired power plants in
June 2014. We expect that EPA’s proposed regulations for both new and existing power plants will negatively
affect the viability of coal-fired power generation, which will ultimately reduce coal consumption and the
production of coal from our properties.
48
In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits
against operators and landowners. In 2012 and 2013, several citizen suit group lawsuits were 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 seek penalties
as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate. While it is too
early to determine the ultimate resolution of these lawsuits, any rulings requiring operators to reduce their
discharges of selenium, conductivity or sulfate could result in large treatment expenses for our lessees. In 2013,
several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including
selenium, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case,
the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond
has been released. 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
would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.
Recent Acquisitions
We are a growth-oriented company and have closed a number of acquisitions over the last several years.
Our most recent acquisitions are briefly described below.
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 $33.7 million, subject to 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 $38.3 million, subject to 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 $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. We
expect to pay approximately $0.7 million in contingent consideration to Anadarko with respect to 2013.
Marcellus Override.
In December 2012, we acquired an overriding royalty interest on approximately
88,000 net acres of overriding royalty interests in oil and gas reserves located in the Marcellus Shale for
$30.3 million.
Hi-Crush Override.
In October 2012, we acquired an overriding royalty interest in frac sand reserves
located on approximately 561 acres near Wyeville, Wisconsin for approximately $15.0 million.
Colt. Between September 2009 and September 2012, we acquired approximately 200 million tons of coal
reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of Foresight Energy, for a total
purchase price of $255 million.
Oklahoma Oil and Gas.
From December 2011 through June 2012, we acquired approximately 19,200 net
mineral acres located in the Mississippian Lime oil play in Northern Oklahoma for $63.9 million.
Sugar Camp.
In March 2012, we acquired the rail loadout and associated infrastructure assets for
$50.0 million and a contractual overriding royalty for $8.9 million interest on certain tonnage at the Sugar Camp
mine in Illinois. The rail loadout and infrastructure assets were purchased from Sugar Camp Energy, LLC and the
contractual overriding royalty interest was purchased from Ruger, LLC, both affiliates of Foresight Energy.
49
Litz-Moore.
In March 2012, we acquired metallurgical coal reserves adjacent to current NRP holdings in
Virginia for $2.8 million.
Royal.
In July 2011, we acquired approximately 44,000 acres of coal reserves and coal bed methane
located in Pennsylvania and Illinois from Royal Oil and Gas Corporation for $8.0 million.
NBR Sand.
In June 2011, we acquired an overriding royalty interest in approximately 711 acres of frac
sand reserves near Tyler, Texas for $16.5 million.
East Tennessee Materials.
In March 2011, we acquired approximately 500 acres of mineral and surface
rights related to limestone reserves in Cleveland, Tennessee near Chattanooga for $4.7 million.
CALX Resources.
In February 2011, we acquired approximately 500 acres of mineral and surface rights
related to limestone reserves on the Tennessee River near Paducah, Kentucky for $16.0 million.
Critical Accounting Policies
Coal and Aggregate Royalties. Coal and aggregate 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, subject to minimum annual or quarterly payments.
Processing and Transportation Fees.
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 coal that is processed and sold from the facilities. The processing leases are
structured 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 coal transported over the beltlines. Under the
terms of the transportation contracts, we receive a fixed price per ton for all coal transported on the beltlines.
Oil and Gas Revenues. Oil and gas royalty revenues are recognized on the basis of volume of
hydrocarbons sold by lessees and the corresponding revenue 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. 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 wells,
including the cost of development and production.
Minimum Royalties. Most of our 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 revenues either when the
lessee recoups the minimum payment through production or immediately following the period during which the
lessee is allowed to recoup the minimum payment.
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 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. Our 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.
Depreciation, Depletion and Amortization. We depreciate our plant and equipment on a straight line basis
over the estimated useful life of the asset. We deplete mineral properties on a units-of-production basis by lease,
50
based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable
tonnage in those properties. We amortize intangible assets on a units-of-production basis, unless classified as a
temporarily idled asset then a minimum amortization is applied. Oil and natural 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 a third-party. Oil and gas royalty interests are depleted on a
straight-line basis over 30 years or the life of the lease, whichever is shorter. We update our estimates of reserves
periodically and this may result in material adjustments to reserves and depletion rates that we recognize
prospectively. Historical revisions have not been material.
Asset Impairment. A long term asset is deemed impaired in most cases when the future expected cash
flow from its use and disposition is less than its book value. Impairment is measured based on the present value
of the projected future cash flow compared to current book value. We have 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. Undiscounted cash flow is used to evaluate recoverability with any adjustment to fair
value to reflect impairment based on discounted cash flows. 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, we intend to closely monitor our coal assets impairment
risk, 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.
Share-Based Payments. We account for our Long-Term Incentive Plan awards under Financial
Accounting Standards Board’s (FASB) stock compensation authoritative guidance. This authoritative guidance
provides that grants must be accounted for 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 value. In addition, this authoritative guidance requires that estimated forfeitures
be included in the periodic computation of the fair value of the liability and that the fair value be recalculated at
each reporting date over the service or vesting period of the grant.
Recent Accounting Pronouncements
In February 2013, the FASB amended the comprehensive income reporting requirements to require an entity
to provide information about the amounts reclassified out of accumulated other comprehensive income by
component. The amendment requires an entity to present, either on the face of the statement where net income is
presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income if the
amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same
reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to
net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide
additional detail about those amounts. The adoption did not have a material impact on the financial statements.
Other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies
are not expected to have a material impact on our financial position, results of operations and cash flows.
51
Results of Operations
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Summary of 2013 and 2012 Revenues and Production
(In thousands, except percent and per ton data)
For the Years Ended
December 31,
2013
2012
Increase
(Decrease)
Percentage
Change
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)
Coal production (tons)
Appalachia
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 gross royalty revenue per ton
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Combined average gross royalty revenue per ton . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
1.27
5.05
6.30
4.00
4.28
2.72
3.39
3.99
Aggregates
Royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aggregate bonus royalty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average gross royalty revenue per ton . . . . . . . . . . . . . . . . . . . . . . . .
$ 7,073
570
$
6,155
1.15
$
$
$
$
$
$
$
$
$
$
$
$
1.50
5.99
7.89
5.00
4.38
3.58
2.60
4.79
$
$
6,598
$
— $
5,287
1.25
$
(0.23)
(0.94)
(1.59)
(1.00)
(0.10)
(0.86)
0.79
(0.80)
475
570
868
(0.10)
(7)%
(33)%
(11)%
(28)%
13%
(11)%
171%
(18)%
10%
(20)%
12%
(10)%
16%
17%
108%
(2)%
(15)%
(16)%
(20)%
(20)%
(2)%
(24)%
30%
(17)%
7%
N/A
16%
(8)%
Investment in OCI Wyoming
Equity and other unconsolidated investment earnings . . . . . . . . . . . .
Cash distributions received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 34,186
$ 72,946
— $ 34,186
— $ 72,946
N/A
N/A
Oil and Gas
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 17,080
$
9,160
$ 7,920
86%
52
Coal Royalty Revenues and Production
Coal royalty revenues comprised approximately 59% of our total revenue for the year ended December 31,
2013 and 69% of our total revenue in 2012. The following is a discussion of the coal royalty revenues and
production derived from our major coal producing regions:
Appalachia.
The combination of lower production in Central Appalachia, a lower royalty rate in Northern
Appalachia on a lease with significant production and generally lower prices being received by our lessees in all
three sub-regions, were the primary reasons coal royalty revenues decreased by $55.7 million in 2013. The
5.3 million ton decrease in production in Central Appalachia was the result of our lessees reducing production in
response to the weaker coal market and the effect of some lessees having a lower proportion of production on our
properties. Production in Northern Appalachia increased by 1.0 million tons, but these increases were mainly on
leases with a lower revenue per ton, and therefore still resulted in reduced revenue of $1.1 million. The tonnage
decreases are partially offset by an increase in production in Southern Appalachia, primarily due to one of our
lessees having more normal production for 2013 after it completed repairs to its preparation plant that was
damaged by a tornado in 2011and restarted production in 2012. Our lessees in Southern Appalachia realized
generally lower prices in 2013 versus 2012, resulting in lower revenue per ton and revenue decrease of
$3.2 million.
Illinois Basin. Coal royalty revenues and production on our properties were both higher in 2013. Coal
royalty revenues increased by $6.5 million and production increased by 1.8 million tons. The increased
production was mainly due to production from our Hillsboro property that operated its longwall for the entire
year of 2013 after beginning operations in the third quarter of 2012. The increased production and revenue from
Hillsboro was partially offset by lower production from the Williamson mine, which had lower sales and lower
production from the Macoupin mine, which idled one of its producing units in early 2013.
Northern Powder River Basin. Our coal royalty revenues decreased by $932,000 over last year despite a
production increase of 401,000 tons on our Western Energy property. The higher production was due to the
normal variations that occur due to the checkerboard nature of our ownership. The lower revenue per ton 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 revenues and production were both higher in 2013. The increase in coal royalty
revenue is primarily due to a mine having a greater proportion of its production on our property.
Aggregates Royalty Revenues and Production
For the year ended December 31, 2013, we recognized $7.6 million in royalty revenue from aggregates,
which included bonus revenue of $0.6 million under one of our leases. For the same period for 2012, we
recognized royalty revenue from aggregates of $6.6 million and no bonus royalty. We had production of
6.2 million tons and 5.3 million tons for 2013 and 2012, respectively. Also, we do not include revenues from our
frac sand properties in Texas and Wisconsin in aggregate royalties, but include those revenues in overriding
royalties. We received revenues of $1.0 million and $1.5 million in 2013 and 2012, respectively, from our Texas
property. We also received $2.1 million in override revenue in 2013 from our frac sand property in Wisconsin,
which was acquired during the fourth quarter of 2012 and did not start to contribute to revenue until 2013.
Oil and Gas Revenues
Oil and gas revenues for the years ended December 31, 2013 and 2012 were $17.1 million and $9.2 million,
respectively. The results for 2013 reflect our further diversification, with investments in oil and gas providing
increased revenues from our Oklahoma properties and revenue from recently acquired non-operated working
interests in the Bakken/Three Forks play in North Dakota and Montana during the second half of 2013. Included
in revenues for the years ended 2013 and 2012 were bonus payments of $0.3 million and $2.6 million,
respectively.
53
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Summary of 2012 and 2011 Revenues and Production
(In thousands, except percent and per ton data)
For the Years Ended
December 31,
2012
2011
Increase
(Decrease)
Percentage
Change
Coal royalty revenues
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 15,768
156,390
29,325
$ 20,578
196,789
11,717
$ (4,810)
(40,399)
17,608
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast
201,483
49,538
8,501
1,212
229,084
41,324
7,658
1,155
(27,601)
8,214
843
57
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$260,734
$279,221
$(18,487)
Coal production (tons)
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast
10,486
26,098
3,718
40,302
11,299
2,377
466
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
54,444
5,251
29,555
1,695
36,501
9,445
2,682
523
49,151
5,235
(3,457)
2,023
3,801
1,854
(305)
(57)
5,293
Average gross royalty revenue per ton
Appalachia
Northern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Southern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Northern Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Combined average gross royalty revenue per ton . . . . . . . . . . . . . .
Aggregates
Royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aggregate bonus royalty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average gross royalty revenue per ton . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
$
$
$
1.50
5.99
7.89
5.00
4.38
3.58
2.60
4.79
$
$
$
$
$
$
$
$
3.92
6.66
6.91
6.28
4.38
2.86
2.21
5.68
6,598
$
— $
5,287
1.25
$
6,640
94
5,930
1.12
$
$
$
$
$
$
$
$
$
$
$
(2.42)
(0.67)
0.98
(1.28)
—
0.72
0.39
(0.89)
(42)
(94)
(643)
0.13
(23)%
(21)%
150%
(12)%
20%
11%
5%
(7)%
100%
(12)%
119%
10%
20%
(11)%
(11)%
11%
(62)%
(10)%
14%
(20)%
—
25%
18%
16%
(1)%
(100)%
(11)%
12%
Oil and Gas
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
9,160
$ 14,017
$ (4,857)
(35)%
54
Coal Royalty Revenues and Production
Coal royalty revenues comprised approximately 69% of our total revenue for the year ended December 31,
2012 and 74% of our total revenue in 2011. The following is a discussion of the coal royalty revenues and
production derived from our major coal producing regions:
Appalachia.
The combination of lower production and lower prices in Central Appalachia, together with a
lower royalty rate in Northern Appalachia, were the primary reasons coal royalty revenues decreased by
$27.6 million in 2012. The 3.5 million ton decrease in production in Central Appalachia was the result of our
lessees reducing production in response to the weaker coal market and the effect of some lessees having a lower
proportion of production on our properties. Production in Northern Appalachia increased by 5.2 million tons, but
these increases were mainly on leases with a lower revenue per ton, and therefore still resulted in reduced
revenue of $4.8 million. The decreases are partially offset by an increase in production and revenue in Southern
Appalachia, due primarily to one of our lessees resuming production for the entire year after it completed repairs
to its preparation plant that was damaged by a tornado in 2011.
Illinois Basin. Coal royalty revenues and production on our properties were both higher in 2012. Coal
royalty revenues increased by $8.2 million and production increased by 1.9 million tons. The increased
production was mainly due to production from our Hillsboro property that began longwall operations in the third
quarter of 2012. In addition, we had increased production at the Williamson mine.
Northern Powder River Basin. Our coal royalty revenues increased by $843,000 over last year despite a
production decrease of 305,000 tons on our Western Energy property. The lower production was due to the
normal variations that occur due to the checkerboard nature of our ownership. The higher revenue per ton was
due to the timing of revenue recognition by the lessee in the third quarter of 2012.
Gulf Coast.
Primarily due to production from a lease with a higher revenue per ton starting on our
property in 2012, coal royalty revenues were higher in 2012 despite production being lower. The increase in
production was more than offset by other lessees having a greater proportion of their production on adjacent
properties. These other properties have lower revenue per ton.
Aggregates Royalty Revenues and Production
For the year ended December 31, 2012, we recognized $6.6 million in royalty revenue from aggregates. For
the same period for 2011, we recognized royalty revenue from aggregates of $6.7 million, which included bonus
revenue of $0.1 million under one of our leases. We had production of 5.3 million tons and 5.9 million tons for
2012 and 2011, respectively. Although production declined, our revenue per ton increased and helped keep the
royalty revenue nearly constant. Also, we do not include revenues from our frac sand properties in Texas and
Wisconsin in aggregate royalties, but include those revenues in overriding royalties. We received $1.5 million in
revenues from the Texas property in 2012.
Oil and Gas Revenues
Oil and gas revenues for the years ended December 31, 2012 and 2011 were $9.2 million and $14.0 million,
respectively. In 2012, we saw a significant decline in royalty revenues from our Louisiana BRP properties due to
low gas prices and reduced drilling activity, which was offset in part by $1.1 million in royalty revenues received
from our recently acquired Oklahoma properties. Included in revenue for the years ended 2012 and 2011 were
bonus payments of $2.6 million and $2.1 million, respectively.
Other Operating Results
Processing and Transportation Revenues. We generated $5.0 million, $8.3 million and $13.5 million in
processing revenues for the years ended December 31, 2013, 2012 and 2011, respectively. Our processing
revenues are derived primarily from our ownership of coal preparation plants. We do not operate the preparation
plants, but receive a fee for material processed through them. Similar to our coal royalty structure, the throughput
fees are based on a percentage of the ultimate sales price for the material that is processed through the facilities.
55
During 2013 and 2012, lower volumes and prices at our plants in Appalachia resulted in lower revenues than in
2011. Also, during 2012 we sold a preparation plant midway through the year which also contributed to lower
revenues in both 2013 and 2012.
In addition to our preparation plants, we own coal handling and transportation infrastructure in Illinois. In
contrast to our typical royalty structure, we receive a fixed rate per ton for coal transported over these facilities.
At the Williamson mine in Illinois, we operate the coal handling and transportation infrastructure and have
subcontracted out that responsibility to a third party. We generated transportation fees from these assets of
approximately $18.0 million, $19.5 million and $16.7 million for the years ended December 31, 2013, 2012 and
2011, respectively. The increase in transportation fees from 2011 to 2012 is due to increased volumes from our
lessee operations ramping up in the Illinois Basin. During 2013, we saw reduced volumes on those transportation
assets resulting in lower revenue.
Additional Revenues and Other Income.
In addition to coal royalties, aggregate royalties, oil and gas
revenues and processing and transportation revenues, we generated approximately 27%, 20% and 13% of our
revenues from other sources for the years ended December 31, 2013, 2012 and 2011, respectively. These other
sources include: income from equity and other unconsolidated investments, property taxes, minimums
recognized as revenues, overriding royalties, timber, rentals, wheelage and other income. In 2013, the income
from our equity investment in OCI Wyoming’s trona mining and soda ash production business contributed $34.2
million to our revenues from other sources. In addition, we received $10.4 million from a right of way
condemnation and recognized $8.3 million from minimums recognized as revenue with $3.5 million of that from
our Macoupin lease. In 2012, we recognized $24.0 million from minimums recognized as revenue. Of the $24.0
million in 2012, we recognized $9.6 million on our Gatling Ohio lease and $8.2 million on our Macoupin lease.
Also included in other revenue in 2012 is a gain from sale of assets of $13.6 million, including $8.5 million from
the sale of a right of way for highway construction and $4.7 million from the sale of a preparation plant. 2011
revenues from other sources did not reflect any unusual transactions.
Operating expenses.
Included in total expenses are:
• Depreciation, depletion and amortization of $64.4 million, $58.2 million and $65.1 million for the years
ended December 31, 2013, 2012 and 2011, respectively. The decrease in 2012 was primarily related to
assets acquired from Gatling, LLC and Gatling Ohio, LLC that were impaired during the third and fourth
quarters of 2011. The increase in 2013 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 $36.8 million, $29.7 million and $29.6 million for the years ended
December 31, 2013, 2012 and 2011, 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 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 $16.5 million, $17.7 million and $14.5 million for the years ended
December 31, 2013, 2012 and 2011, respectively. A substantial portion of our property taxes 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 $64.4 million, $54.0 million and $49.2 million for the years ended
December 31, 2013, 2012 and 2011, respectively. Interest increased due to additional debt incurred in 2013 and
2012 to fund acquisitions as well as a refinancing of our low-interest credit facility and payment on our low-
interest term loan with 9.125% high yield notes.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
Generally, we satisfy our working capital requirements with cash generated from operations. We finance our
property acquisitions with available cash, borrowings under our revolving credit facility, and the issuance of our
56
senior notes and additional common units. While our ability to satisfy our debt service obligations and pay
distributions to our unitholders depends in large part on our future operating performance, our ability to make
acquisitions will depend on prevailing economic conditions in the financial markets as well as the coal, oil and
gas and aggregates/industrial minerals industries and other factors, some of which are beyond our control. For a
more complete discussion of factors that will affect cash flow we generate from operations, see Item 1A,
“Risk Factors.” Our capital expenditures, other than for acquisitions, have historically been minimal. However,
we incur capital expenditures and operating expenses associated with the non-operated working interests in oil
and gas assets. We finance those capital expenditures through a combination of cash flow from operations and
borrowings under the NRP Oil and Gas revolving credit facility.
In September 2013, NRP, together with NRP Finance as co-issuer, sold $300.0 million of 9.125% Senior
Notes due 2018 at an issue price of 99.007% of par value for net proceeds of $289 million. We used the net
proceeds of the offering to repay all outstanding borrowings under Opco’s revolving credit facility. Opco’s
revolving credit facility does not mature until August 2016 and, as of December 31, 2013, Opco had $280 million
in available capacity under the facility. In August 2013, NRP Oil and Gas entered into a senior secured, reserve-
based revolving credit facility with an initial $8.0 million borrowing base. The borrowing base was increased to
$16.0 million in connection with the closing of the Sundance acquisition in December 2013. As of December 31,
2013, NRP Oil and Gas had the full $16.0 million available for borrowing under its revolving credit facility. As
of the date of this filing, NRP Oil and Gas had $2.0 million of borrowings outstanding under its credit facility.
We typically access the capital markets to refinance amounts outstanding under our revolving credit facilities as
we approach the limits under those facilities, the timing of which depends on the pace and size of our acquisition
program and development capital expenditures associated with our oil and gas business.
We refinanced a $35 million Opco senior note that matured in 2013, as well as $15 million of the remaining
$52 million in principal payments due on Opco’s senior notes during 2013. We have $81.0 million in principal
payments on Opco’s senior notes due in 2014. While we intend to reduce our leverage by paying the full amount
with cash from operations, we may refinance some or all of these obligations as they come due.
We used $91.0 million of net proceeds from the September 2013 senior notes offering to repay principal on
Opco’s term loan. We also used a portion of the proceeds from the July 2013 $44.8 million special distribution
from OCI Wyoming to repay $10.0 million of principal on Opco’s term loan. Opco’s next principal repayment
obligation on the term loan is in January 2016, when Opco will be required to repay the remaining principal
amount outstanding thereunder of $99.0 million.
In addition to the amounts available under our revolving credit facilities, we had $92.5 million in cash at
December 31, 2013. We believe that the combination of our capacity under our revolving credit facilities and our
cash on hand gives us enough liquidity to meet our current financial needs. Other than $81 million in principal
repayments due on Opco’s senior notes each year for the next several years, we do not have any debt maturing
until 2016. In January 2014, our Board of Directors declared a cash distribution of $0.35 per unit with respect to
the fourth quarter of 2013. The distribution represents a $0.20 (36%) decrease over the distribution declared and
paid with respect to the third quarter of 2013. We believe that the distribution decrease will save NRP
approximately $89.6 million annually and position NRP to reduce its debt over time while preserving its liquidity
to pursue accretive acquisitions. Our debt covenant ratios are in compliance for both revolving credit facilities
and Opco’s outstanding senior notes. For a more complete discussion of factors that will affect our liquidity, see
Item 1A, “Risk Factors.”
Net cash provided by operations for the years ended December 31, 2013, 2012 and 2011 was
$247.1 million, $271.4 million and $305.6 million, respectively. The majority of our cash provided by operations
is generated from coal royalty revenues and, beginning in 2013, our equity interest in OCI Wyoming.
Net cash used in investing activities for the years ended December 31, 2013, 2012 and 2011 was
$302.8 million, $212.7 million and $115.1 million, respectively. Our 2013 investing activities consisted of the
acquisitions of the interest in OCI Wyoming and the 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
57
Sugar Camp. These uses in 2012 were slightly offset by $24.8 million in proceeds from asset sales. During 2011,
substantially all of our investing activities consisted of acquiring reserves, plant and equipment and other rights.
Net cash flows used in financing activities for the years ended December 31, 2013, 2012 and 2011 was
$1.2 million, $124.2 million and $71.1 million, respectively. During 2013, 2012 and 2011 we had proceeds from
loans of $567.0 million, $148.0 million and $385.0 million, respectively. During 2013, 2012 and 2011, these
proceeds were offset by repayment of debt of $386.2 million, $30.8 million and $210.5 million, respectively.
Also during 2013, 2012 and 2011 we paid cash distributions to our unitholders of $249.0 million, $240.8 million
and $234.8 million, respectively. During 2013, we had net proceeds from an issuance of common units of
$74.9 million, together with a capital contribution from our general partner of $1.5 million.
Contractual Obligations and Commercial Commitments
NRP Debt
Senior Notes.
In September 2013, NRP and NRP Finance as co-issuer completed a private placement of
$300 million principal amount of 9.125% Senior Notes due 2018. 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.
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
58
the ability of certain of its subsidiaries to declare or pay any dividend or distribution on, purchase or redeem units
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:
• $20.0 million drawn under the floating rate revolving credit facility, due August 2016;
• $99.0 million floating rate term loan, due January 2016;
• $23.1 million of 4.91% senior notes due 2018;
• $128.6 million of 8.38% senior notes due 2019;
• $53.8 million of 5.05% senior notes due 2020;
• $1.5 million of 5.31% utility local improvement obligation due 2021;
• $27.0 million of 5.55% senior notes due 2023;
• $75.0 million of 4.73% senior notes due 2023;
• $165.0 million of 5.82% senior notes due 2024;
• $50.0 million of 8.92% senior notes due 2024;
• $175.0 million of 5.03% senior notes due 2026; and
• $50.0 million of 5.18% senior notes due 2026.
Senior Notes. Opco issued the senior notes listed below 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.
The scheduled principal payments on Opco’s 8.92% senior notes due in 2024 will begin in March 2014, and the
scheduled principal payments on Opco’s 4.73%, 5.03% and 5.18% senior notes will begin in December 2014.
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 $280 million in available borrowing
capacity under its revolving credit facility. 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.
59
During 2013, Opco’s borrowings and repayments under its 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 . . . . . .
$148,000
—
—
$148,000
43,000
—
$ 191,000
7,000
(198,000)
$ —
20,000
—
Outstanding balance, ending period . . . . . . . . .
$148,000
$191,000
$
—
$20,000
Opco’s obligations under its credit facility are unsecured but are guaranteed by its subsidiaries. Opco may
prepay all amounts outstanding under its 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 credit agreement 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.
Term Loan.
In connection with the OCI Wyoming acquisition, Opco entered into a 3-year, $200 million
term loan facility in January 2013. The term loan facility is guaranteed by Opco’s operating subsidiaries and bore
interest at a weighted average rate of 2.43% in 2013. Interest on the term loan became payable initially in
April 2013. We repaid $101 million of the term loan during 2013. The remaining balance of $99.0 million is due
on January 23, 2016. The term loan facility contains financial covenants and other terms that are identical to
those of our credit facility.
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. The credit facility had an
initial borrowing base of $8.0 million, which was increased to $16.0 million in connection with the closing of the
Sundance acquisition in December 2013. 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, 2013, NRP Oil and Gas did not have any borrowings outstanding under the credit facility and had
the full $16.0 million available for borrowing thereunder. As of the date of this filing, NRP Oil and Gas had
$2.0 million outstanding under the facility.
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 1.75% to 2.75%.
60
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.
OCI Wyoming Contingent Consideration Payment
In January 2013, we acquired non-controlling equity interests in OCI Wyoming Co. (OCI Co) and OCI
Wyoming, L.P. (OCI LP), an operator of a trona mining and soda ash refining business. At the time of
acquisition, (1) the acquired interests comprised a 48.51% general partner interest in OCI LP and 20% of the
common stock and 100% of the preferred stock in OCI Co, (2) OCI Co owned a 1% limited partner interest in
OCI LP and the right to receive a $14.5 million annual priority distribution and (3) 80% of the common stock in
OCI Co was owned by OCI Chemical Corporation, and the remaining 50.49% general partner interest in OCI LP
was owned by OCI Wyoming Holding Co., a subsidiary of OCI Chemical Corporation.
The three investments were acquired from Anadarko Holding Company (Anadarko) and its subsidiary, Big
Island Trona Company for $292.5 million. The purchase price was funded from the proceeds of a $200 million
term loan, $76.5 million in equity and GP interests issued in a private placement and the balance from operating
cash. The acquisition agreement provides for a net present value of up to $50 million in cumulative additional
contingent consideration payable by us should certain performance criteria be met at OCI LP as defined in the
purchase and sale agreement in any of the years 2013, 2014 or 2015. At December 31, 2013, we accrued $15
million of contingent consideration that is included in Equity and other unconsolidated investments. The current
portion of $0.7 million is included in Accounts payable and accrued liabilities and the long term portion of $14.3
million is included in Other non-current liabilities.
In July 2013, OCI LP was reorganized pursuant to a series of transactions in connection with an initial
public offering by OCI Resources LP, an affiliate of OCI Chemical Corporation, of its interest in OCI LP. In
connection with such reorganization, we exchanged our common stock and preferred stock in OCI Co for a
limited partner interest in OCI LP, and OCI Resources LP became the owner of the limited partner interests in
OCI LP that were previously owned by OCI Wyoming Holding Co. Following the reorganization, our interest in
OCI LP increased to 49%, consisting of both limited and general partner interests. The restructuring did not have
any impact on the operations, revenues, management or control of OCI LP.
With respect to the contingent consideration, in February 2014, Anadarko raised in oral discussions with us
whether the reorganization transactions triggered an acceleration of our obligation to pay the additional
contingent consideration in full. Although Anadarko has not made a formal claim against us, Anadarko has
indicated that it may do so in the near future. We do not believe the reorganization transactions triggered an
obligation to pay the additional contingent consideration, and we will continue to engage in discussions with
Anadarko to resolve Anadarko’s concerns. However, if Anadarko were to prevail on such a claim, we would be
61
required to pay an amount to Anadarko in excess of the $15 million accrual described above up to the maximum
amount of the additional contingent consideration. Any such additional amount would be considered to be
additional acquisition consideration and added to Equity and other unconsolidated investments. We expect to pay
any incremental amount with borrowings under our revolving credit facility or cash from operations. Any such
borrowings and payments would reduce the amounts otherwise available to us for acquisitions and other
opportunities.
Consolidated Debt
The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2013
(in millions):
Contractual Obligations
Total
2014
2015
2016
2017
2018
Thereafter
Payments Due by Period
NRP:
Long-term debt principal payments
(including current maturities)(1) . . . . . . .
. . . . .
Long-term debt interest payments(2)
Opco:
Long-term debt principal payments
. . . . . .
(including current maturities) (3)
Long-term debt interest payments(4)
. . . . .
Rental leases(5) . . . . . . . . . . . . . . . . . . . . . .
$ 300.0 $ — $ — $ — $ — $300.0
27.4
137.9
28.3
27.4
27.4
27.4
$ —
—
868.0
230.4
3.4
81.0
43.5
0.7
81.0
38.4
0.7
200.0
33.3
0.7
81.0
28.2
0.7
81.0
23.2
0.6
344.0
63.8
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,539.7 $153.5 $147.5 $261.4 $137.3 $432.2
$407.8
(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.
(2) The amounts indicated in the table include interest due on 9.125% senior notes, which accrued from
September 18, 2013, the issue date of the senior notes.
(3) The amounts indicated in the table include principal due on Opco’s senior notes, as well as the utility local
improvement obligation related to our property in DuPont, Washington. On January 24, 2013, Opco entered
into a $200 million three year term loan. As of December 31, 2013, there was $99.0 million outstanding
which is due in January 2016.
(4) The amounts indicated in the table include interest due on Opco’s senior notes as well as the utility local
improvement obligation related to our property in DuPont, Washington.
(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. These rental obligations are included in the table above.
Shelf Registration Statements and “At-the-Market” Program
On April 24, 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. This shelf replaced our previous
shelf registration statement, which expired at the end of February 2012.
On August 15, 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 on
September 21, 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
62
up to $500 million in equity securities of NRP. On November 12, 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 will be made pursuant to the shelf registration statement declared effective in September
2012. We did not sell any units under the ATM program in 2013.
On April 12, 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. 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, 2013, 2012 and 2011.
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. Because we have no employees, employees of Western Pocahontas
Properties Limited Partnership 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, 2013. 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.
63
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. On January 8, 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. President Obama has directed EPA to
issue proposed regulations on existing fossil fuel-fired power plants in June 2014. We expect that EPA’s proposed
regulations for both new and existing power plants will negatively affect the viability of coal-fired power generation,
which will ultimately reduce coal consumption and the production of coal from our properties.
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,480
(In thousands)
$9,791
$9,136
For additional information, see Item 13, “Certain Relationships and Related Transactions, and Director
For the Years Ended
December 31,
2013
2012
2011
Independence — Omnibus Agreement.”
Transactions with Cline Affiliates
Various companies controlled by Chris Cline, including Foresight Energy, 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 filing.
At December 31, 2013, we had accounts receivable totaling $7.7 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 $51.7 million on our Consolidated Balance Sheets. Revenues from the Cline affiliates are as follows:
Coal royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Processing fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimums recognized as revenue . . . . . . . . . . . . . . . . . . . . . . . . . . .
Override revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
64
For The Years Ended
December 31,
2013
2012
2011
$54,322
1,281
17,977
3,477
3,226
8,149
(In thousands)
$48,567
2,409
19,514
17,785
4,066
—
$42,474
2,975
16,689
—
2,691
2,990
$88,432
$92,341
$67,819
As of December 31, 2013, we had received $71.4 million in minimum royalty payments that have not been
recouped by Cline affiliates, of which $20.0 million was received in 2013.
We recognized an asset impairment of $90.9 million during the third quarter of 2011 related to certain of
our assets at the Gatling West Virginia location and $70.4 million during the fourth quarter of 2011 related to the
Gatling Ohio location. During the fourth quarter of 2012, we recognized an additional impairment of $2.6 million
related to the assets at the Gatling West Virginia location.
During 2013 and 2011, we recognized non-cash gains of $8.1 million and $3.0 million on reserve exchanges
in Illinois with Williamson Energy. The tons received during 2013 were fully mined during 2013 and the tons
received during 2011 were fully mined in 2012, while the tons exchanged are not included in the current mine
plans. The gains are included in Other revenues on the Consolidated Statement of Comprehensive Income.
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. Subsequent to the
end of the second quarter, 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, 2013, 2012 and 2011, the revenues from Taggart were as follows:
For the Years Ended
December 31,
2013
2012
2011
Processing revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,761
(In thousands)
$5,580
$9,755
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 of the Consolidated Statements of Income for the third
quarter of 2012. The net book value of the asset sold was $7.6 million. During 2013, Taggart was sold to Forge
and 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:
Coal royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,594
(In thousands)
$3,486
$1,629
NRP also had accounts receivable totaling $0.3 million from Corsa at December 31, 2013.
For the Years Ended
December 31,
2013
2012
2011
65
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
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 our 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, 2013, we had $119 million outstanding in variable interest debt. If interest rates were to
increase by 1%, annual interest expense would increase approximately $1.2 million, assuming the same principal
amount remained outstanding during the year.
66
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of independent registered public accounting firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated balance sheets as of December 31, 2013 and 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of comprehensive income for the years ended December 31, 2013, 2012 and
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of partners’ capital for the years ended December 31, 2013, 2012 and 2011 . . . . .
Consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011 . . . . . . . . . .
Notes to consolidated financial statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
68
69
70
71
72
73
67
NATURAL RESOURCE PARTNERS L.P.
CONSOLDATED FINANCIAL STATEMENTS
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, 2013 and 2012, 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, 2013. 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 LP
(OCI Wyoming) (a Limited Partnership in which Natural Resource Partners LP owns a 49% interest). Natural
Resource Partners LP’s investment in OCI Wyoming constituted approximately $269 million of Natural
Resource Partners LP’s assets as of December 31, 2013 and Natural Resource Partners LP’s equity in the net
income of OCI Wyoming constituted approximately $34 million of Natural Resource Partners LP’s Net Income
for the period ended December 31, 2013. OCI Wyoming’s financial statements were audited by other auditors
whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for OCI
Wyoming, 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 provide a
reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to
above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P.
at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the
three years in the period ended December 31, 2013, 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,
2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission “1992 framework” and our report dated February 28,
2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2014
68
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit information)
December 31,
2013
December 31,
2012
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net of allowance for doubtful accounts . . . . . . . . . . . . . . . . . .
Accounts receivable — affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
$
92,513
33,737
7,666
1,691
$ 149,424
35,116
10,613
1,042
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
135,607
24,340
26,435
1,405,455
66,950
269,338
11,502
51,732
497
196,195
24,340
32,401
1,380,473
70,766
—
4,291
55,576
630
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,991,856
$1,764,672
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
8,659
391
80,983
8,341
7,830
17,184
$
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued incentive plan expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Partners’ capital:
123,388
142,586
10,526
14,341
1,084,226
3,693
957
87,230
7,718
7,952
10,265
117,815
123,506
8,865
—
897,039
Common units outstanding: (109,812,408 and 106,027,836) . . . . . . . . . . . . . . . . . .
General partner’s interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
606,774
10,069
324
(378)
605,019
10,026
2,845
(443)
Total partners’ capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
616,789
617,447
Total liabilities and partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,991,856
$1,764,672
The accompanying notes are an integral part of these financial statements.
69
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands, except per unit data)
For the Years Ended December 31,
2013
2012
2011
Revenues:
Coal royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity and other unconsolidated investment income . . . . . . . . . . . . . . . . . . .
Aggregate royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Processing fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimums recognized as revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Override royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$212,663 $260,734 $279,221
—
6,734
13,475
16,688
14,017
12,640
9,148
14,523
11,237
—
6,598
8,299
19,513
9,160
15,273
23,956
15,527
20,087
34,186
7,643
5,049
17,977
17,080
15,416
8,285
13,499
26,319
Total revenues and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
358,117
379,147
377,683
Operating expenses:
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, franchise and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas lease operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal royalty and override payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
64,377
734
36,821
16,463
739
1,644
1,103
58,221
2,568
29,714
17,678
—
1,944
1,857
65,118
161,336
29,553
14,486
—
2,033
1,022
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
121,881
111,982
273,548
Income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense)
236,236
267,165
104,135
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(64,396)
238
(53,972)
162
(49,180)
69
Income before non-controlling interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
172,078
—
213,355
—
55,024
(998)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$172,078 $213,355 $ 54,026
Net income attributable to:
General partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3,442
$
4,267
$
1,081
Limited partners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$168,636 $209,088 $ 52,945
Basic and diluted net income per limited partner unit . . . . . . . . . . . . . . . . . . . .
$
1.54
$
1.97
$
0.50
Weighted average number of common units outstanding . . . . . . . . . . . . . . . . .
109,584
106,028
106,028
Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$172,143 $213,405 $ 54,079
The accompanying notes are an integral part of these financial statements.
70
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands, except unit data)
Balance at December 31, 2010 . . .
Distributions . . . . . . . . . . . . . . . . .
Non-controlling interest
adjustment . . . . . . . . . . . . . . . . .
Costs associated with equity
transactions . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . .
Net income for the year ended
December 31, 2011 . . . . . . . . . .
Loss on interest hedge . . . . . . . . .
Comprehensive income . . . . . . . .
Common Units
Units
Amounts
General
Partner
Amounts
Non-
Controlling
Interest
Amounts
Accumulated
Other
Comprehensive
Income (Loss)
Total
106,027,836
$ 806,529
— (230,080)
$14,132
(4,696)
$ 5,065
(52)
$(546)
—
$ 825,180
(234,828)
—
—
—
—
—
—
—
(141)
—
—
—
—
52,945
—
—
1,081
—
—
(373)
—
998
—
—
—
—
—
—
—
53
53
(373)
(141)
998
54,026
53
54,079
Balance at December 31, 2011 . . .
106,027,836
$ 629,253
$10,517
$ 5,638
$(493)
$ 644,915
Distributions . . . . . . . . . . . . . . . . .
Costs associated with equity
transactions . . . . . . . . . . . . . . . .
Net income for the year ended
December 31, 2012 . . . . . . . . . .
Loss on interest hedge . . . . . . . . .
Comprehensive income . . . . . . . .
— (233,263)
(4,758)
(2,793)
—
(59)
—
— 209,088
—
—
—
—
4,267
—
—
—
—
—
—
—
—
—
50
50
(240,814)
(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 . . . . . . . . . . . . . . . . .
Net income for the year ended
December 31, 2013 . . . . . . . . . .
Interest rate swap from
unconsolidated investments . . .
Loss on interest hedge . . . . . . . . .
Comprehensive income . . . . . . . .
3,784,572
—
75,000
—
—
1,531
—
—
—
(293)
— (241,588)
—
(4,930)
—
(2,521)
— 168,636
3,442
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
13
52
65
75,000
1,531
(293)
(249,039)
172,078
13
52
172,143
Balance at December 31, 2013 . . .
109,812,408
$ 606,774
$10,069
$
324
$(378)
$ 616,789
The accompanying notes are an integral part of these financial statements.
71
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
2013
2012
2011
Cash flows from operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to net cash provided by operating activities:
$ 172,078
$ 213,355
$ 54,026
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-controlling interest
Change in operating assets and liabilities:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued incentive plan expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, franchise and other taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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
65,118
625
(2,990)
—
—
(1,058)
161,336
998
(6,951)
90
854
950
31,277
1,909
(610)
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
247,074
271,408
305,574
Cash flows from investing activities:
Acquisition of land, coal, other mineral rights and related intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of equity interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions from unconsolidated investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition or construction of plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Return on direct financing lease and contractual override . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in direct financing lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(72,000)
(293,085)
48,833
—
10,929
2,558
—
(180,534)
—
—
(681)
24,822
2,669
(59,009)
(120,284)
—
—
(404)
5,600
—
—
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(302,765)
(212,733)
(115,088)
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital contribution by general partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
567,020
75,000
(9,209)
(386,230)
—
(293)
(249,039)
1,531
148,000
—
—
(30,800)
(500)
(59)
(240,814)
—
385,000
—
(2,957)
(210,519)
(7,625)
(141)
(234,828)
—
Net cash used in financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,220)
(124,173)
(71,070)
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(56,911)
149,424
(65,498)
214,922
119,416
95,506
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 92,513
$ 149,424
$ 214,922
Supplemental cash flow information:
Cash paid during the period for interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 55,191
$ 53,842
$ 47,653
Non-cash investing activities:
Non-controlling interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Note receivable related to sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash contingent consideration on equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
— $
$ 15,000
— $
1,808
—
373
—
—
Non-cash financing activities:
Purchase obligation related to reserve and infrastructure acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
— $
500
The accompanying notes are an integral part of these financial statements.
72
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 and managing mineral properties in the United States.
The Partnership owns coal reserves in the three major coal-producing regions of the United States: Appalachia,
the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. As of
December 31, 2013, the Partnership owned or controlled approximately 2.3 billion tons of proven and probable
coal reserves (unaudited), and also owned approximately 500 million tons of aggregate reserves (unaudited) in a
number of states across the country. The Partnership does not operate any mines, but leases reserves to
experienced mine operators under long-term leases that grant the operators the right to mine reserves in exchange
for royalty payments. Lessees are generally required to make royalty payments based on the higher of a
percentage of the gross sales price or a fixed price per ton, in addition to a minimum payment.
In addition, the Partnership owns coal and aggregate transportation and preparation equipment, other coal
related rights and oil and gas properties on which it earns revenue.
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
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 venture with International Paper Company controlled by the Partnership.
Intercompany transactions and balances have been eliminated.
Business Combinations
For purchase acquisitions accounted for as a business combination, 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.
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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 Equivalents and Restricted Cash
The Partnership considers all highly liquid short-term investments with an original maturity of three months
or less to be cash equivalents.
Accounts Receivable
Accounts receivable from the Partnership’s lessees 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 lessees’ accounts and when it becomes aware of a specific 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 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. If circumstances related to specific lessees change, the
Partnership’s estimates of the recoverability of receivables could be further adjusted.
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 investment 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, 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 their estimated useful life while indefinite-
lived intangibles, if any, and goodwill is 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.
An investee’s accounts are not included in the Partnership’s Consolidated Balance Sheets and Statements of
Comprehensive Income. However, 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
74
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.
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 as of December 31, 2013.
Land and Mineral Rights
Land and mineral rights owned and leased are recorded using the FASB’s business combination and asset
purchase authoritative guidance. 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, or over the amortization period of the lease. 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 lease, whichever is shorter.
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, which when originally recorded range from three to twenty years.
Intangible Assets
The Partnership’s intangible assets consist of above-market contracts. Intangible assets are identified related
to contracts acquired when compared to the estimate of current market rates for similar contracts. The estimated
fair value of the above-market rate contracts are determined based on the present value of future cash flow
projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis
except that a minimum amortization is calculated on a straight line basis for temporarily idled assets.
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s
revolving credit facility and senior notes. These costs are amortized over the term of the debt.
75
Asset Impairment
A long term asset is deemed impaired in most cases when the future expected cash flow from its use and
disposition is less than its book value. Impairment is measured based on the present value of the projected future
cash flow compared to current book value. 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. Undiscounted cash flow is used to evaluate recoverability with any adjustment to fair
value to reflect impairment based on discounted cash flows. 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, the Partnership intends to closely monitor its coal assets
impairment risk, 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. See Note 6. “Asset Impairments.”
Revenues
Coal and Aggregate Royalties. Coal and aggregate 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 and Transportation Fees. 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 royalty revenues are recognized on the basis of volume of
hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make
payments based on a percentage of the selling price. 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. Revenues related to the Partnership’s non-operated working interests in oil and gas
assets are recognized on the basis of our net revenue interests in hydrocarbons produced. 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 wells, including the cost of development and production.
Minimum Royalties. Most of the Partnership’s 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 royalty
revenue when the lessee recoups the minimum payment through production. The deferred revenue is recognized
as minimums recognized as revenue in the period immediately following the expiration of the lessee’s ability to
recoup the payments.
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
76
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.
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
reimbursement of property taxes is included in property tax revenue 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.
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.
New Accounting Standards
In February 2013, the FASB amended the comprehensive income reporting requirements to require an entity
to provide information about the amounts reclassified out of accumulated other comprehensive income by
component. The amendment requires an entity to present, either on the face of the statement where net income is
presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income if the
amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same
reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to
net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide
additional detail about those amounts. The adoption did not have a material impact on the financial statements.
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.
3. Significant Acquisitions
Sundance. On December 19, 2013, the Partnership completed the acquisition of non-operated working
interests in the Williston Basin of North Dakota from Sundance Energy, Inc. The Partnership accounted for the
transaction in accordance with the authoritative guidance for business combinations. The identification of all
assets acquired and liabilities assumed as well as the valuation process required for the allocation of the purchase
price is not complete. Pending the final purchase price adjustments and allocation, the assets acquired for
approximately $33.7 million 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 the Williston Basin of North Dakota and Montana from Abraxas Petroleum. The Partnership accounted for the
77
transaction in accordance with the authoritative guidance for business combinations. The identification of all
assets acquired and liabilities assumed as well as the valuation process required for the allocation of the purchase
price is not complete. Pending the final purchase price adjustments and allocation, the assets acquired for
approximately $38.3 million are included in mineral rights in the accompanying Consolidated Balance Sheets.
Revenues and costs from the working interests for 2013 of $4.6 million and $2.2 million, respectively, are
included from June 17, 2013, the effective date of acquisition.
Marcellus Override.
In December 2012, the Partnership acquired an overriding royalty interest on
approximately 88,000 net acres of overriding royalty interests in oil and gas reserves located in the Marcellus
Shale for $30.3 million.
Colt.
In September 2009, the Partnership signed a definitive agreement to acquire approximately
200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of
Foresight Energy, through several separate transactions for a total purchase price of $255 million. During the
year ended December 31, 2012, the Partnership paid $80.0 million to complete the acquisition of reserves at this
mine.
Oklahoma Oil and Gas. From December 2011 through June 2012, the Partnership acquired approximately
19,200 net mineral acres located in the Mississippian Lime oil play in Northern Oklahoma for approximately
$63.9 million, of which 15,600 net mineral acres were acquired during 2012 for $51.3 million.
Sugar Camp.
In March 2012, the Partnership acquired from Sugar Camp Energy, an affiliate of Foresight
Energy, the rail loadout and associated infrastructure assets at the Sugar Camp mine in Illinois for total
consideration of $50.0 million. At the time of the acquisition, the Partnership also entered into a lease agreement
related to the rail loadout and associated facilities that has been accounted for as a direct financing lease. The
lease provides for payments based upon tons of coal transported over the facilities subject to quarterly recoupable
minimum payments of $1.25 million. The lease is for a term of 20 years but may be extended by the lessee. Total
projected remaining payments under the lease at December 31, 2013 are $91.2 million with unearned income of
$42.8 million. The unearned income will be reflected as transportation fees over the term of the lease using the
effective interest method. Any amounts in excess of the contractual minimums will be recorded as transportation
fees when earned. The net amount receivable under the lease as of December 31, 2013 was $48.5 million, of
which $1.6 million is included in accounts receivable – affiliates while the remaining is included in long-term
contracts receivable—affiliate. The Partnership recognized $5.1 million in transportation fees during the year
ended December 31, 2013 related to this lease.
In a separate transaction, the Partnership acquired, from Ruger, LLC, an affiliate of Foresight Energy, a
contractual overriding royalty interest for $8.9 million that will provide 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 payments the Partnership receives with respect to the
overriding royalty will be reflected partially as a return of the initial investment and partially as override revenue
over the life of the contract using the effective interest method based upon actual production and adjusted
periodically for differences in projected and actual production. The net amount receivable under the agreement as
of December 31, 2013 was $6.1 million of which $1.2 million is included in accounts receivable – affiliates while
the remaining is included in long-term contracts receivable—affiliate. The Partnership recognized $1.3 million in
overriding royalty during the year ended December 31, 2013 related to the contractual overriding royalty interest.
4. Equity and Other Investments
In January 2013, the Partnership acquired non-controlling equity interests in OCI Wyoming Co. (OCI Co)
and OCI Wyoming, L.P. (OCI LP), an operator of a trona mining and soda ash refinery business. At the time of
acquisition, (1) the acquired interests comprised a 48.51% general partner interest in OCI LP and 20% of the
common stock and 100% of the preferred stock in OCI Co, (2) OCI Co owned a 1% limited partner interest in
OCI LP and the right to receive a $14.5 million annual priority distribution and (3) 80% of the common stock in
OCI Co was owned by OCI Chemical Corporation, and the remaining 50.49% general partner interest in OCI LP
was owned by OCI Wyoming Holding Co., a subsidiary of OCI Chemical Corporation.
78
The three investments were acquired from Anadarko Holding Company (Anadarko) and its subsidiary, Big
Island Trona Company for $292.5 million. The purchase price was funded from the proceeds of a $200 million
term loan, $76.5 million in equity and GP interests issued in a private placement and the balance from operating
cash. 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 be met at OCI LP as
defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015. At December 31, 2013, the
Partnership accrued $15 million of contingent consideration that is included in Equity and other unconsolidated
investments. The current portion of $0.7 million is included in Accounts payable and accrued liabilities and the
long term portion of $14.3 million is included in Other non-current liabilities.
In July 2013, OCI LP was reorganized pursuant to a series of transactions in connection with an initial
public offering by OCI Resources LP, an affiliate of OCI Chemical Corporation, of its interest in OCI LP. In
connection with such reorganization, the Partnership exchanged its common stock and preferred stock in OCI Co
for a limited partner interest in OCI LP, and OCI Resources LP became the owner of the limited partner interests
in OCI LP that were previously owned by OCI Wyoming Holding Co. Following the reorganization, the
Partnership’s interest in OCI LP increased to 49%, consisting of both limited and general partner interests. The
restructuring did not have any impact on the operations, revenues, management or control of OCI LP.
With respect to the contingent consideration, in February 2014, Anadarko raised in oral discussions with the
Partnership whether the reorganization transactions triggered an acceleration of the Partnership’s obligation to
pay the additional contingent consideration in full. Although Anadarko has not made a formal claim against the
Partnership, Anadarko has indicated that it may do so in the near future. The Partnership does not believe the
reorganization transactions triggered an obligation to pay the additional contingent consideration, and the
Partnership will continue to engage in discussions with Anadarko to resolve Anadarko’s concerns. However, if
Anadarko were to prevail on such a claim, the Partnership would be required to pay an amount to Anadarko in
excess of the $15 million accrual described above up to the maximum amount of the additional contingent
consideration. Any such additional amount would be considered to be additional acquisition consideration and
added to Equity and other unconsolidated investments.
The Partnership engaged a valuation specialist to assist in identifying and valuing the assets and liabilities of OCI
Wyoming at the date of acquisition, including the land, mine, plant and equipment as well as identifiable intangible
assets. Included in fair value adjustments, is an increase in the Partnership’s proportionate fair value of property, plant
and equipment of $58.0 million, which will be depreciated using the straight-line method over a weighted average life
of 28 years. Also, $133.0 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 amount 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 investments. For the year ended December 31, 2013, amortization of basis difference of
$2.9 million was recorded by the Partnership.
The following summarized financial information as of December 31, 2013 and the results of operations for
the year then ended were taken from the OCI-prepared unaudited financial statements.
Operating results:
Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income allocation to NRP’s equity interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of basis difference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity and other unconsolidated investment income . . . . . . . . . . . . . . . . . . . . . . . . . . . .
79
For the Year
Ended
December 31,
2013
(In thousands)
$442,132
$ 94,299
$ 79,655
$ 37,036
$ (2,850)
$ 34,186
Balance Sheet information:
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Members equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities and capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 interests . . . . . . . . . .
December 31,
2013
(In thousands)
(Unaudited)
$201,265
$193,277
1,231
$
$395,773
$ 39,663
$155,000
3,779
$
$197,331
$395,773
$ 96,692
$269,338
$172,646
5. Allowance for Doubtful Accounts
Activity in the allowance for doubtful accounts for the years ended December 31, 2013, 2012 and 2011 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
2013
2012
2011
(In thousands)
$393
$ 681
$ 711
278
—
278
(714)
318
—
318
—
71
(359)
(288)
—
Balance, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 275
$711
$ 393
6. Asset Impairments
For the year ended December 31, 2013, the Partnership recorded asset impairments of $0.7 million on two
aggregate properties on BRP LLC. There were no other impairments recorded during 2013.
Gatling West Virginia.
In October 2011, the Partnership was informed by Gatling, LLC, a Cline affiliate,
that it was idling the operations and was no longer projecting production from the West Virginia mine. The
Partnership and Gatling amended the lease with respect to this property to provide that the existing minimum
royalty balance of $24.1 million was non-recoupable, that Gatling pay $3.4 million in non-recoupable minimum
royalties when they became due in January and April of 2012, that the minimums would be reduced after the first
quarter of 2012, and that Gatling would continue to maintain and ventilate the mine. Following the amendment,
Gatling satisfied all terms of the lease. Considering all information available at the time of amendment, the
Partnership determined that its investment in the Gatling West Virginia property was not fully recoverable by
future cash flows. The assets at the time of amendment included coal reserves, certain above market intangibles
and coal transportation equipment.
The 2011 asset impairment of $118.4 million was offset by $24.1 million of recoupable minimum payments
received from Gatling, LLC to date and $3.4 million in cash payments received in 2012, resulting in a net asset
80
impairment of $90.9 million, which is included in operating expenses on the Consolidated Statements of
Comprehensive Income.
In December 2012, the Partnership was informed by Gatling that it was dismantling their preparation plant
and removing it from the site and cancelling the lease effective June 2013. The Partnership considered this new
information as another impairment triggering event and reassessed the remaining coal reserves and coal
transportation equipment fair values for impairment. The fair values of both the remaining reserves and
transportation equipment were determined using Level 2 market approaches based upon recent comparable
transactions. The reserves were adjusted for the mine’s specific characteristics. The 2012 asset impairment of
$2.6 million is included in operating expenses on the Consolidated Statements of Comprehensive Income. There
were no further indicators of impairment since December 2012 on this property.
The net book value and calculated fair values of the assets relating to the Gatling West Virginia operation
were as follows:
2012 Measurement Date
2011 Measurement Date
Fair
Value
Net Book
Value
Fair
Value
Net Book
Value
Coal and other mineral rights, net . . . . . . . . . . . . . . . .
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,050
—
1,981
$6,031
(In thousands)
$6,618
—
1,981
$8,599
$6,618
—
2,600
$9,218
$ 76,003
43,855
7,775
$127,633
Gatling Ohio.
In December 2011, the Partnership was informed by Gatling Ohio, LLC, a Cline affiliate,
that it was idling its operations and was no longer projecting production from the Ohio mine. Gatling Ohio’s
recoupable minimum royalty balance as of December 31, 2011 was $9.6 million. Considering all information the
Partnership determined that its investment in the Gatling Ohio property would not be fully recovered by future
cash flows. The assets include coal reserves, certain above market intangibles and coal transportation equipment.
The asset impairment of $70.4 million is included in operating expenses in 2011 on the Consolidated Statements
of Income. There were no further indicators of impairment since December 2012 on this property.
The net book value as of the measurement date and calculated fair values of the assets relating to the Gatling
Ohio operation are as follows:
2011 Measurement Date
Fair Value
Net Book
Value
(In thousands)
Coal and other mineral rights, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant and equipment, net
$20,035
—
2,947
$56,769
33,670
2,947
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$22,982
$93,386
In determining the 2011 impairments of the Gatling West Virginia and Gatling Ohio assets, the fair values
of the coal rights were estimated using a weighted combination of Level 3 expected cash flow and Level 2
market approaches. The fair values of the transportation equipment were estimated using Level 2 market
approaches. The expected cash flows were developed using estimated annual sales tons, as well as forecasted
sales prices and anticipated market royalty rates. The market approaches include references to recent comparable
transactions that were adjusted for each mine’s specific characteristics. Since Gatling, LLC is no longer
projecting production in the near term future for the West Virginia and Ohio properties, the related royalty and
transportation contract intangible assets were estimated to have no fair value as of the measurement date.
81
7.
Plant and Equipment
The Partnership’s plant and equipment consist of the following:
Plant and equipment at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 55,271
(28,836)
$ 55,271
(22,870)
Net book value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 26,435
$ 32,401
December 31,
2013
December 31,
2012
(In thousands)
For the years ended
December 31,
2013
2012
2011
Total depreciation expense on plant and equipment
. . . . . . . . . . . . . . . .
$5,966
(In thousands)
$6,825
$8,589
During the third quarter of 2012, the Partnership sold a preparation plant to Taggart Global USA, LLC, a
related party, 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 in 2012 and it
is included in Other revenues of the Consolidated Statements of Comprehensive Income. The note receivable
balance at December 31, 2012 was $1.7 million and was paid in full during 2013.
8. Mineral Rights
The Partnership’s mineral rights consist of the following:
Mineral rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depletion and amortization . . . . . . . . . . . . . . . . . . . . . .
$1,894,920
(489,465)
$1,815,423
(434,950)
Net book value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,405,455
$1,380,473
December 31,
2013
December 31,
2012
(In thousands)
For the years ended
December 31,
2013
2012
2011
Total depletion and amortization expense on mineral interests . . . . .
$54,595
(In thousands)
$47,042
$47,230
9.
Intangible Assets
Amounts recorded as intangible assets along with the balances and accumulated amortization at
December 31, 2013 and 2012 are reflected in the table below:
Contract intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 89,421
(22,471)
$ 89,421
(18,655)
Net book value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 66,950
$ 70,766
December 31,
2013
December 31,
2012
(In thousands)
Total amortization expense on intangible assets . . . . . . . . . . . . . . . . . . .
$3,816
(In thousands)
$4,354
$9,298
For the years ended
December 31,
2013
2012
2011
82
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, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For year ended December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,126
3,543
3,508
3,508
3,508
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:
December 31,
2013
December 31,
2012
(In thousands)
NRP LP Debt:
$300 million 9.125% senior notes, with semi-annual interest
payments in April and October, maturing October 2018, issued at
99.007% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$297,170
$
—
Opco Debt:
$300 million floating rate revolving credit facility, due
August 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$200 million floating rate term loan, due January 2016 . . . . . . . . . . . .
5.55% senior notes, with semi-annual interest payments in June and
20,000
99,000
148,000
—
December, maturing June 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
35,000
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
interest payments, maturing in March 2021 . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . .
23,084
27,700
128,571
150,000
53,846
61,538
1,538
1,731
27,000
30,300
75,000
75,000
83
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 . . . . . . . . . . . . . . . . . .
NRP Oil and Gas Debt:
December 31,
2013
December 31,
2012
(In thousands)
165,000
180,000
50,000
50,000
175,000
175,000
50,000
50,000
Reserve-based revolving credit facility due 2018 . . . . . . . . . . . . . . . . .
—
—
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less — current portion of long term debt . . . . . . . . . . . . . . . . . . . . . . . . .
1,165,209
(80,983)
984,269
(87,230)
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,084,226
$897,039
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 at an offering price of 99.007% of par value. 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.
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 $87.0 million on its senior notes during the year ended
December 31, 2013. 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.
84
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, 2013 and year ended December 31, 2012
were 2.23% and 2.09%, 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.
Term Loan Facility. During the first quarter of 2013, Opco also issued $200 million in term debt. The
weighted average interest rate for the debt outstanding under the term loan for the twelve months ended
December 31, 2013 was 2.43%. Opco repaid $101 million in principal under the term loan during the third
quarter of 2013. Repayment terms call for the remaining outstanding balance of $99 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 non-operated working interests in oil and gas assets located in the Bakken/Three Forks play
acquired on August 9, 2013. The credit facility has a borrowing base of $16.0 million as of December 31, 2013
and is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. At
December 31, 2013, there were no borrowings outstanding under the credit facility.
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 1.75% to 2.75%.
NRP Oil and Gas will incur 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.
85
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.
Consolidated Principal Payments
The consolidated principal payments due are set forth below:
NRP LP
OPCO
NRP
Oil & Gas
Senior Notes
Senior Notes Credit Facility Term Loan Credit Facility
Total
$
2014 . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . .
— $ 80,983
80,983
—
80,983
—
80,983
—
80,983
344,124
—
300,000(1)
(In thousands)
$ —
—
20,000
—
—
—
$ —
—
99,000
—
—
—
$300,000
$749,039
$20,000
$99,000
$—
—
—
—
—
—
$—
$
80,983
80,983
199,983
80,983
380,983
344,124
$1,168,039
(1) The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2013 were carried at
$297.2 million.
NRP LP, Opco and NRP Oil and Gas were in compliance with all terms under their long-term debt as of
December 31, 2013.
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 and Taggart preparation plant sale 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, Taggart note receivable and long-term senior notes are as follows:
Fair Value As Of
Carrying Value As Of
December 31,
2013
December 31,
2012
December 31,
2013
December 31,
2012
(In thousands)
Assets
Sugar Camp override, current and
long-term . . . . . . . . . . . . . . . . . . . . .
Taggart plant receivable, current and
long term . . . . . . . . . . . . . . . . . . . . . .
$
$
6,852
—
$
$
8,817
1,668
$
$
6,063
—
$
$
7,495
1,667
Liabilities
Long-term debt, current and
long-term . . . . . . . . . . . . . . . . . . . . .
$1,071,880
$876,574
$1,046,209
$836,269
86
The fair value of the Sugar Camp override, Taggart plant receivable and long-term debt is estimated by
management using comparable term risk-free treasury issues with a market rate component determined by
current financial instruments with similar characteristics which is a Level 3 measurement. Since the Partnership’s
credit facility is variable rate debt, its fair value approximates its carrying amount.
12. Related Party Transactions
Reimbursements to Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its
management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the
general partner and its affiliates are reimbursed for 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 our general partner and
its affiliates.
The reimbursements to affiliates of the Partnership’s general partner for services performed by Western
Pocahontas Properties and Quintana Minerals Corporation are as follows:
For the Years Ended
December 31,
2013
2012
2011
Reimbursement for services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,480
(In thousands)
$9,791
$9,136
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, 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, 2013. At
December 31, 2013, the Partnership had accounts receivable totaling $7.7 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 $51.7 million on the Partnership’s Consolidated Balance Sheets. Revenues from the Cline
affiliates are as follows:
Coal royalty revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Processing fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimums recognized as revenue . . . . . . . . . . . . . . . . . . . . . . . . . . .
Override revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For The Years Ended
December 31,
2013
2012
2011
$54,322
1,281
17,977
3,477
3,226
8,149
(In thousands)
$48,567
2,409
19,514
17,785
4,066
—
$42,474
2,975
16,689
—
2,691
2,990
$88,432
$92,341
$67,819
As of December 31, 2013, the Partnership had received $71.4 million in minimum royalty payments that
have not been recouped by Cline affiliates, of which $20.0 million was received in the current year.
The Partnership recognized an asset impairment of $90.9 million during the third quarter of 2011 related to
certain of the Partnership’s assets at the Gatling WV location and $70.4 million during the fourth quarter of 2011
87
related to certain assets at the Gatling Ohio location. During the fourth quarter of 2012, the Partnership
recognized an additional asset impairment of $2.6 million related to the assets at the Gatling WV location due to
receiving a termination notice in December 2012 that the lease was cancelled as of June 2013.
During 2013 and 2011, the Partnership recognized gains of $8.1 million and $3.0 million on a reserve swap
in Illinois with Williamson Energy. 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 2013 were fully mined during 2013 and the tons received during 2011 were fully mined
during 2012, while the tons exchanged are not included in the current mine plans. The gains are located in Other
revenues on the Consolidated Statements of Comprehensive Income.
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. Subsequent to the
end of the second quarter, 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, 2013, 2012 and 2011, the revenues from Taggart were as follows:
For the Years Ended
December 31,
2013
2012
2011
Processing revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,761
(In thousands)
$5,580
$9,755
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 Other income of the
Consolidated Statements of Income for the third quarter of 2012. The net book value of the asset sold was
$7.6 million. During 2013, when Taggart was sold to Forge 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 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,594
(In thousands)
$3,486
$1,629
At December 31, 2013, the Partnership also had accounts receivable totaling $0.3 million from Corsa.
For the Years Ended
December 31,
2013
2012
2011
88
13. 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.
Environmental Compliance
The operations our lessees conduct on the Partnership’s 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. 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, aggregates and industrial mineral 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. Because the Partnership has no employees, employees of
Western Pocahontas Properties Limited Partnership make 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 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.
The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the
Partnership related to our properties for the period ended December 31, 2013. 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 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. On January 8, 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. President
Obama has directed EPA to issue proposed regulations on existing fossil fuel-fired power plants in June 2014.
The Partnership expects that EPA’s proposed regulations for both new and existing power plants will negatively
affect the viability of coal-fired power generation, which will ultimately reduce coal consumption and the
production of coal from the Partnership’s properties.
14. 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, 2013, 2012, and 2011. Revenues from these lessees are as follows:
For the Years Ended
December 31,
2013
2012
2011
Revenues
Percent
Revenues
Percent
Revenues
Percent
(Dollars in thousands)
Foresight Energy and affiliates . . . .
Alpha Natural Resources . . . . . . . .
$88,432
$55,147
24.7% $92,341
15.4% $81,077
24.4% $ 67,819
21.4% $107,267
18.0%
28.4%
89
In 2013, the Partnership derived 40.1% of its revenue from 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 an affiliate of Foresight Energy, the exposure is spread over a
number of different mining operations and leases. Foresight’s Williamson mine alone was responsible for
approximately 13.0%, 12.4% and 11.7% of our total revenues for 2013, 2012 and 2011, respectively.
Substantially all of the Partnership’s accounts receivable result from amounts due from third-party
companies in the coal industry, with approximately 41% of our 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.
15.
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
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, 2013 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
912,314
369,947
(246,372)
(22,905)
Outstanding grants at the end of the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,012,984
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 0.18% to 0.80% and 24.33% to 31.94%, respectively at December 31, 2013.
The Partnership’s cumulative average dividend rate of 7.32% was used in the calculation at December 31, 2013.
The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $9.6 million,
$2.9 million and $7.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. In connection
with the Long-Term Incentive Plans, cash payments of $7.0 million, $6.6 million and $5.7 million were paid
during each of the years ended December 31, 2013, 2012, and 2011, respectively. The grant date fair value was
$25.27, $33.38 and $42.93 per unit for awards in 2013, 2012 and 2011, 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
90
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, 2013,
was $9.3 million.
16. Subsequent Events (Unaudited)
The following represents material events that have occurred subsequent to December 31, 2013 through the
time of the Partnership’s filing its Form 10-K with the SEC:
Distributions
On January 9, 2014, the Partnership declared a distribution of $0.35 per unit to be paid on January 31, 2014
to unitholders of record on January 21, 2014.
Dividends and Distributions Received From Unconsolidated Equity and Other Investments
Subsequent to December 31, 2013, the Partnership received $11.6 million in cash distributions from its
investments in OCI.
17. Supplemental Financial Data (Unaudited)
Shown below are selected unaudited quarterly data.
Selected Quarterly Financial Information
(In thousands, except per unit data)
2013
Total revenues and other income . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . . .
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
$ 94,332
$ 14,762
$ 62,528
$ 47,906
0.43
$
$ 86,804
$ 17,411
$ 55,332
$ 41,065
0.37
$
$ 82,237
$ 17,852
$ 51,624
$ 36,126
0.32
$
$ 94,744
$ 14,352
$ 66,752
$ 46,981
0.42
$
outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
108,887
109,812
109,812
109,812
2012
Total revenues and other income . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . . .
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
$ 91,872
$ 12,409
$ 64,824
$ 51,309
0.47
$
$ 90,664
$ 15,172
$ 63,492
$ 49,938
0.46
$
$ 94,175
$ 14,485
$ 65,643
$ 52,001
0.48
$
$102,436
$ 16,155
$ 73,206
$ 60,107
0.56
$
outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
106,028
106,028
106,028
106,028
91
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, 2013. 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, 2013 based on the framework in
Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission “1992 Framework” (COSO). Based on that evaluation, our management concluded that
our internal control over financial reporting was effective as of December 31, 2013. No changes were made to
our internal control over financial reporting during the last fiscal quarter that materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s
consolidated financial statements included in this 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,
2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission “1992 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 Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether effective internal control over financial reporting was maintained in all material respects. Our
audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
92
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.
In our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2013, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2013 and
2012, 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, 2013 of Natural Resource Partners L.P. and our report dated
February 28, 2014 expressed an unqualified opinion thereon.
/s/
Ernst & Young LLP
Houston, Texas
February 28, 2014
Item 9B. Other Information
None.
93
PART III
Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance
As a master limited partnership we do not employ any of the people responsible for the management of our
properties. Instead, we reimburse affiliates of our managing general partner, GP Natural Resource Partners LLC,
for their services. The following table sets forth information concerning the directors and officers of GP Natural
Resource Partners LLC as of the date of this report. 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.
Nick Carter . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . .
Dennis F. Coker . . . . . . . . . . . . . . . . .
Kevin J. Craig . . . . . . . . . . . . . . . . . .
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
66
67
60
42
57
46
45
40
62
39
57
59
72
63
57
72
68
53
43
52
67
Position with the General
Partner
Chairman of the Board and Chief Executive Officer
President and Chief Operating Officer
Chief Financial Officer and Treasurer
Executive Vice President
Executive Vice President, Operations
Vice President, Aggregates
Vice President, Business Development
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
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.
Nick Carter has served as President and Chief Operating Officer of GP Natural Resource Partners LLC
since 2002. He has also served as President of the general partner of Western Pocahontas Properties Limited
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Partnership and New Gauley Coal Corporation since 1990 and as President of the general partner of Great
Northern Properties Limited Partnership from 1992 to 1998. Prior to 1990, Mr. Carter held various positions with
MAPCO Coal Corporation and was engaged in the private practice of law. He is Chairman of the National
Council of Coal Lessors, a past Chair of the West Virginia Chamber of Commerce and a board member of the
Kentucky Coal Association, West Virginia Coal Association, Indiana Coal Council, National Mining
Association, ACCCE, Foundation for the Tri-State Community, Inc., Community Trust Bancorp, Inc. and Vigo
Coal Company, Inc.
Dwight L. Dunlap has served as the Chief Financial Officer and Treasurer of GP Natural Resource Partners
LLC since 2002. Mr. Dunlap has served as Vice President and Treasurer of Quintana Minerals Corporation since
1987 and as Chief Financial Officer, Treasurer and Assistant Secretary of the general partner of Western
Pocahontas Properties Limited Partnership, Chief Financial Officer and Treasurer of Great Northern Properties
Limited Partnership and Chief Financial Officer, Treasurer and Secretary of New Gauley Coal Corporation since
2000. Mr. Dunlap has worked for Quintana Minerals Corporation since 1982. Mr. Dunlap is a Certified Public
Accountant with over 30 years of experience in financial management, accounting and reporting including six
years of audit experience with an international public accounting firm.
Wyatt L. Hogan has served as Executive Vice President of GP Natural Resource Partners since December
2013. Mr. Hogan was Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC 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 Partnership Committee of OCI Wyoming L.P. Prior to joining Vinson & Elkins in
August 2000, Mr. Hogan practiced corporate and securities law at Andrews & Kurth L.L.P. from September
1997 through July 2000.
Kevin F. Wall has served as Executive Vice President, Operations of GP Natural Resource Partners LLC
since December 2008. Mr. Wall served 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 Partnership Committee of OCI Wyoming L.P. 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.
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 14 years focused on corporate development activity. Mr. Coker also
represents NRP as one of its appointees to the Partnership Committee for OCI Wyoming L.P. Mr. Coker also
serves on the Executive Board as Treasurer of the National Stone Sand and Gravel Association.
Kevin J. Craig is the Vice President of Business Development for GP Natural Resource Partners LLC.
Mr. Craig joined NRP in 2005 from CSX Transportation, where he served as Terminal Manager for the West
Virginia Coalfields. He has extensive marketing and finance experience with CSX since 1996. Mr. Craig also
serves 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 currently serves as Chairman of the Committee on Energy. Prior to
joining CSX, he served as a Captain in the United States Army.
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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 Board of Trustees of
numerous publicly listed closed-end and exchange traded 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 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 as Chairman of the Board of United Coal Company, LLC
and as 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 and an emeritus
member of the School of Accountancy 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 also has been involved in
numerous charitable organizations throughout his career.
Corbin J. Robertson, III joined the Board of Directors of GP Natural Resource Partners LLC in May 2013.
Mr. Robertson has experience with investments in a variety of energy businesses, having served both in
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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. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc,
including Senior Vice President — Shared Services from January 2008 to June 2008, Senior Vice President and
Treasurer from January 2004 to December 2007, and Senior Vice President — Finance from April 2003 to
December 2003. From November 2000 to January 2003, Mr. Smith served as President and Chief Operating
Officer — Corporate Services for NiSource Inc. Prior to joining NiSource, Mr. Smith served as Deputy Chief
Financial Officer for Columbia Energy Group from November 1999 to November 2000 and Chief Financial
Officer for Columbia Gas Transmission Corporation and Columbia Gulf Transmission Company from 1996 to
1999.
Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007.
Mr. Vecellio brings extensive experience in the aggregates and coal mine development industry to the Board of
Directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the
late 1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio
Group, Inc, a major aggregates producer, contractor and oil terminal developer/operator in the Mid-Atlantic and
Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with
Vecellio & Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996
to November 2002. Mr. Vecellio is the former Chairman of the American Road and Transportation Builders and
is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations.
Corporate Governance
Board Attendance and Executive Sessions
During 2013, there were several changes to the Board of Directors of GP Natural Resource Partners LLC. In
May 2013, W.W. Scott, Jr. retired from the Board, and Corbin J. Robertson, III was appointed to serve on the
Board. In October 2013, David M. Carmichael retired from the Board, and J. Matthew Fifield resigned from the
Board. Messrs. Gordy, Holcomb and Navarre were appointed to the Board in October 2013.
The Board met ten times in 2013. During that period, every director attended all of the Board meetings, with
the exception of Mr. Fifield, who missed two meetings prior to his resignation from the Board in October 2013,
and Mr. Scott, who missed one meeting prior to his resignation from the Board in May 2013. During 2013, our
non-management directors met in executive session several times. The presiding director of the February meeting
was David Carmichael, the Chairman of our Compensation, Nominating and Governance Committee, or CNG
Committee, at that time. The presiding director of the December meeting was Robert T. Blakely, the Chairman of
the CNG Committee following Mr. Carmichael’s retirement from the Board in October 2013. In addition, our
independent directors met one time in executive session in May 2013. Mr. Carmichael was the presiding director
at this 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.
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Independence of Directors
The Board of Directors has affirmatively determined that Messrs. Blakely, Carmichael, 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 2013, because we are a limited partnership as defined in Section 303A of the
NYSE’s listing standards, we are not required to do so. The Board has an Audit Committee, a Compensation,
Nominating and Governance Committee, and a Conflicts Committee, each of which is staffed solely by
independent directors.
Audit Committee
Our Audit Committee is comprised of Robert B. Karn III, who serves as chairman, Robert T. Blakely,
Richard A. Navarre and Stephen P. Smith. Mr. Carmichael served on the audit committee until his retirement in
October 2013, and Mr. Navarre joined the committee in December 2013. 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 2013, 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, 2013 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 2013 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 and annual reporting on Form 10-Q and Form 10-K prior to filing with the Securities and
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Exchange Commission. In 2013, 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.
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, 2013, for filing
with the Securities and Exchange Commission.
Robert B. Karn III, Chairman
Robert T. Blakely
Stephen P. Smith
Richard A. Navarre
Compensation, Nominating and Governance Committee Authority
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. Mr. Carmichael served on the Committee until his retirement from the Board in October 2013.
The CNG Committee has reviewed and approved the compensation arrangements described in the Compensation
Discussion and Analysis section of this 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 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 2013 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 2013.
On August 12, 2013, J. Matthew Fifield (who served on our Board of Directors from January 2007 to
October 2013), filed one Form 4 reporting three purchases of common units that had not been previously
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reported on a timely basis. These purchases reported by Mr. Fifield were made in 2012 and 2013 pursuant to an
automatic distribution reinvestment feature in a brokerage account. In addition, on August 26, 2013, Corbin J.
Robertson, Jr. filed a Form 4 that reported his ownership of 2,000 common units that had not been previously
reported on a timely basis. Mr. Robertson has held those units since our initial public offering in 2002 (giving
effect to the two-for-one unit split in 2007).
Partnership Agreement
Investors may view our partnership agreement and the amendments to the partnership agreement on our
website at www.nrplp.com. The partnership agreement and the amendments are also filed with the SEC and are
available in print to any unitholder that requests them.
Corporate Governance Guidelines and Code of Business Conduct and Ethics
We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and
Ethics that applies to our management, and complies with Item 406 of Regulation S-K. Our Corporate
Governance Guidelines and our Code of Business Conduct and Ethics are available on our website at
www.nrplp.com and are available in print upon request.
NYSE Certification
Pursuant to Section 303A of the NYSE Listed Company Manual, in 2013, 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 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 primary objective in
determining the compensation of our executive officers is to 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 DERs tied to long-term equity-based compensation. The DERs are contingent rights, granted in
tandem with specific phantom units, to receive an amount in cash equal to the cash distributions made by NRP
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with respect to its units during the period such phantom unit are outstanding. As discussed further below, our
decision to reduce the distribution with respect to the fourth quarter of 2013 will result in significantly reduced
compensation for our executive officers in 2014. 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
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 95% 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 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 distributions equal to the distributions paid on our common units. 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
2013. 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 factor 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.”
Role of Our Executive Officers in the Compensation Process
Mr. Robertson and Mr. Carter provided recommendations to the CNG Committee in its evaluation of the
2013 compensation programs for our executive officers. Mr. Carter provided Mr. Robertson with
recommendations relating to the executive officers, other than himself, that are based in Huntington.
Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for
all of the executive officers, including the Houston-based officers other than himself. Mr. Robertson and
Mr. Carter relied on their personal experience in setting compensation over a number of years in determining the
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appropriate amounts for each employee, and considered each of the factors described elsewhere in this
compensation discussion and analysis. Mr. Robertson and Mr. Carter 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 2013 executive officer compensation programs.
Evaluation of 2013 Performance; Components of Compensation
2013 Performance
In 2013, we spent approximately $365 million to acquire additional assets that will help secure the future
growth of the partnership. These acquisitions consisted of the purchase of the 49% interest in OCI Wyoming’s
trona mining and soda ash production business and the acquisition of non-operated working interests in oil and
gas assets in the Williston Basin of North Dakota and Montana. These efforts are reflective of NRP
management’s desire to continue to grow and diversify the partnership to ensure the stability of future revenues
and distributions to our unitholders.
In terms of financial performance, we recorded revenues in 2013 of $358.1 million, which were 6% lower
than our revenues in 2012. In addition, our 2013 earnings of $1.54 per unit were less than the $2.00 per unit in
2012 (after accounting for non-cash impairment charges in 2012). However, our distributable cash flow was up
3.5% compared to 2013, with the cash distributions received from OCI Wyoming offsetting decreased coal
royalty revenues. These results were consistent with the guidance that we issued to the public markets in
February 2013 as updated in August 2013.
Looking forward, coal royalty revenues are expected to continue to decline during 2014 as a result of lower
expected pricing and production volumes. The reduced coal royalty revenues, together with increased interest
expense related to NRP’s 9 1⁄ 8% senior notes issued in September, result in a substantial decrease in projected
distributable cash flow for 2014 as compared to distributable cash flow for 2013, as disclosed in the guidance
that we issued in January 2014. As a result, our Board of Directors decreased the quarterly distribution to our
unitholders with respect to the fourth quarter of 2013. The decreased quarterly distribution has resulted in
substantially lower trading prices for our units to date in 2014 as compared to the 2013 trading prices. The
quarterly distribution level and unit trading prices are important criteria for our CNG Committee when
considering compensation.
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 and 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 2014, at the December 2013 meeting, the CNG
Committee considered the financial performance of NRP for the nine months ended September 30, 2013 as well
as the projected financial performance of NRP for the fourth quarter of 2013 and for the year ending
December 31, 2014. The CNG Committee also considered the individual performance of each member of the
executive management team during 2013 and the changes to the management team that became effective on
December 17, 2013. Based on its review, the CNG Committee determined to increase 2014 salaries for those
members of the management team whose responsibilities at NRP have increased beginning in 2014 by 5% over
2013 salaries and to hold salaries constant for the other members of the management team as compared to 2013.
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Annual Cash Incentive Awards
Each named executive officer, other than Mr. Robertson, participated in two cash incentive programs in
2013. The first program is a discretionary cash bonus award approved in February 2014 by the CNG Committee
based on similar criteria used to evaluate the annual base salaries and based on the January 2014 distribution
reduction. The bonuses awarded with respect to 2013 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. For the reasons stated above under “—2013 Performance,” the CNG
Committee reduced 2013 bonuses to the executive officers by 10% as compared to 2012.
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
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. The amounts received
by the named executive officers, other than Mr. Robertson, were held constant in 2013, as the per unit
distribution actually paid by NRP during the calendar year ended December 31, 2013 was held constant relative
to 2012. In determining the total compensation package for each executive officer, the CNG Committee
considered the likelihood that the cash incentive payments to NRP’s executive officers made from a portion of
the cash distributions on common units held by our general partner will be lower in future years relative to 2013
to the extent that NRP’s quarterly distribution level remains below the $0.55 per quarter level actually paid in
2013. 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 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. 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 2014 LTIP awards for NRP’s executive officers, at the February 2014 meeting, the CNG
Committee considered the financial performance of NRP for the year ended December 31, 2013 as well as the
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projected financial performance of NRP for the year ending December 31, 2014. The CNG Committee also
considered the reduction in the distribution with respect to the fourth quarter of 2013 declared in January 2014
and the related decline in NRP’s unit price following the declaration of the reduced distribution. The CNG
Committee determined to increase 2014 LTIP awards for NRP’s executive officers by 5% over 2013 LTIP
awards. In approving the 2014 LTIP awards, the CNG Committee also considered the decreased value realized
by each executive officer for LTIP awards vesting in 2014 as compared to 2013 as a result of NRP’s decreased
quarterly distribution level and related lower unit trading price.
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. Carter, Dunlap, Hogan and Wall under the defined contribution plan
exceeded $10,000 in each of 2011, 2012 and 2013, but did not exceed $25,000 for any individual in any year.
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 2011, 2012 and 2013 we also reimbursed Quintana and Western
Pocahontas for car allowances provided to Messrs. Carter, Dunlap and Wall.
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, 2013, our named executive officers held 302,000 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 2011, 2012 or 2013. 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.
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Report of the Compensation, Nominating and Governance Committee
The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by
Item 402(b) of Regulation S-K with management. Based on the reviews and discussions referred to in the
foregoing sentence, the CNG Committee recommended to the board of directors that the Compensation
Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2013.
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 2011, 2012 and 2013 based on time allocated by each individual to Natural Resource Partners. In
2013, Messrs. Robertson, Dunlap, Carter, Hogan and Wall spent approximately 50%, 97%, 97%, 96% and 95%,
respectively, of their time on NRP matters.
Name and Principal Position
Corbin J. Robertson, Jr. . . . . . . . . . . . . . . .
Chairman and CEO
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . .
CFO and Treasurer
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . .
President and Chief Operating Officer
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . .
Executive Vice President
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . .
Executive Vice President,
Operations
Year
2013
2012
2011
2013
2012
2011
2013
2012
2011
2013
2012
2011
2013
2012
2011
Salary
($)
Bonus
($)
—
—
—
328,193
325,189
313,885
378,300
378,300
368,600
344,970
328,337
315,865
205,485
205,485
199,500
—
—
—
126,900
141,000
156,500
199,260
221,400
246,000
126,900
141,000
156,500
126,900
141,000
155,000
Phantom
Unit
Awards(1)
($)
712,000
830,400
1,156,980
222,500
259,500
315,540
356,000
415,200
525,900
222,500
259,500
315,540
222,500
259,500
315,540
All Other
Compensation(2)
($)
Total
($)
—
—
—
38,537
37,577
36,755
40,473
39,851
39,228
31,358
30,988
30,095
33,781
33,781
33,013
712,000
830,400
1,156,980
716,130
763,266
822,680
974,033
1,054,751
1,179,728
725,728
759,825
818,000
588,666
639,766
703,053
(1) Amounts represent the grant date fair value of unit awards determined in accordance with FASB stock
compensation authoritative guidance.
(2)
Includes portions of automobile allowance, 401(k) matching and retirement contributions allocated to
Natural Resource Partners by Quintana Minerals Corporation and Western Pocahontas Properties Limited
Partnership. The payments made to Messrs. Carter, Dunlap, Hogan and Wall under the defined contribution
plan exceeded $10,000 in each of 2011, 2012 and 2013, but did not exceed $25,000 for any individual in
any year. 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
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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.
Individual
Corbin J. Robertson, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Grants of Plan-Based Awards in 2013
Named Executive Officer
Corbin J. Robertson, Jr. . . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall
Grant Date
2/13/2013
2/13/2013
2/13/2013
2/13/2013
2/13/2013
Compensation
Received from General
Partner and Not
Reimbursed by NRP
$
456,000
456,000
530,000
391,000
391,000
385,000
536,000
536,000
530,000
391,000
391,000
385,000
391,000
391,000
385,000
Year
2013
2012
2011
2013
2012
2011
2013
2012
2011
2013
2012
2011
2013
2012
2011
All Other
Unit Awards:
Number of
Phantom Units(1)
(#)
Grant Date
Fair Value of
Unit Awards(2)
($)
32,000
10,000
16,000
10,000
10,000
712,000
222,500
356,000
222,500
222,500
(1) The phantom units were granted in February 2013 and will vest in February 2017.
(2) Amounts represent the estimated fair value on February 13, 2013.
None of our executive officers has an employment agreement, and the salary, bonus and phantom unit
awards noted above are approved by the CNG Committee. See our disclosure under “— Compensation
Discussion and Analysis” for a description of the factors that the CNG Committee considers in determining the
amount of each component of compensation.
Subject to the rules of the exchange upon which the common units are listed at the time, the board 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
107
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, 2013
The table below shows the total number of outstanding phantom units held by each named executive officer
at December 31, 2013. 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 2014, 2015, 2016 and 2017.
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
130,000
37,000
61,000
37,000
37,000
3,383,650
950,340
1,682,040
950,340
950,340
(1) Based on a unit price of $19.94, the closing price for the common units on December 31, 2013. The value
also includes the value of the accrued DERs as of December 31, 2013.
Phantom Units Vested in 2013
The table below shows the phantom units that vested with respect to each named executive officer in 2013,
along with the value realized by each individual.
Named Executive Officer
Number of
Phantom Units That
Vested
(#)
Value Realized on
Vesting
($)
Corbin J. Robertson, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35,000
8,000
14,000
8,000
8,000
1,075,200
245,760
430,080
245,760
245,760
Potential Payments upon Termination or Change in Control
None of our executive officers have entered into employment agreements with Natural Resource Partners or
its affiliates. Consequently, there are no severance benefits payable to any executive officer upon the termination
of their employment. The annual base salaries, bonuses and other compensation are all determined by the CNG
Committee in consultation with Mr. Robertson, Mr. Carter and the full board of directors. 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
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of a change in control on the outstanding equity-based awards at December 31, 2013, based on the 20-day
average of the common units of $19.86 on December 31, 2013 and includes amounts for accrued DERs.
Named Executive Officer
Corbin J. Robertson, Jr.
. . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of
Phantom
Units
That Have
Not Vested
(#)
130,000
37,000
61,000
37,000
37,000
Potential
Post-Employment
Payments
Required Upon
Change in
Control
($)
Potential
Cash Payments
Required Upon
Change in
Control
($)
—
—
—
—
—
3,373,250
947,380
1,677,160
947,380
947,380
Directors’ Compensation for the Year Ended December 31, 2013
The table below shows the directors’ compensation for the year ended December 31, 2013. As with our
named executive officers, we do not grant any options or restricted units to our directors.
Name
Fees Earned
or Paid in
Cash
($)
Phantom
Unit
Awards(2)(3)
($)
Robert Blakely . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
David Carmichael(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
J. Matthew Fifield(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Russell Gordy(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Donald Holcomb(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert Karn III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S. Reed Morian . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Richard Navarre(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corbin J. Robertson, III(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stephen Smith . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
W. W. Scott, Jr.(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leo A. Vecellio, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
85,000
70,833
50,000
10,000
10,000
85,000
60,000
10,000
30,000
65,000
30,000
65,000
102,285
454,903
102,285
—
—
102,285
102,285
—
—
102,285
496,560
102,285
Total
($)
187,285
525,736
152,285
10,000
10,000
187,285
162,285
10,000
30,000
167,285
526,560
167,285
(1) Messrs. Carmichael and Fifield served on the Board until October 31, 2013. Mr. Scott served on the Board
until May 22, 2013. Corbin J. Robertson, III was appointed to the Board effective May 22, 2013.
Messrs. Gordy, Holcomb and Navarre were appointed to the Board effective October 31, 2013.
(2) Amounts represent the grant date fair value of unit awards determined in accordance with FASB stock
compensation authoritative guidance. Mr. Fifield forfeited all of his outstanding LTIP units upon his
resignation from the Board. Upon Mr. Scott’s retirement from the Board, the Board agreed to vest Mr. Scott
in his remaining LTIP units. Pursuant to the Board’s policy, Mr. Carmichael retired from the Board upon
reaching age 75, and vested in his units upon the completion of his final term as a director.
(3) As of December 31, 2013, except for Messrs. Gordy, Holcomb and Navarre who hold 11,980 phantom units
that vest in annual increments of 1,000 units in 2014, 3,580 units in 2015, 3,700 units in 2016 and 3,700
units that vest in 2017, each director held 14,455 phantom units that vest in annual increments of 3,475 units
in 2014, 3,580 units in 2015, 3,700 units in 2016 and 3,700 units in 2017.
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In 2013, 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.
2014 Long-Term Incentive Awards
In February 2014, the CNG Committee awarded 33,600 phantom units to Mr. Robertson, 16,800 phantom
units to Mr. Carter, and 10,500 phantom units to each of Messrs. Dunlap, Hogan and Wall. 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 2018. The CNG Committee also approved an award of 3,885 phantom units, including tandem
DERs, to each of the members of the Board of Directors. These phantom units will vest in February 2018.
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2013, Messrs. Blakely, Karn and Vecellio served on the CNG
Committee during the full year. Mr. Carmichael served on the CNG Committee as its Chairman during 2013 until
his retirement from the Board on October 31, 2013. Upon Mr. Carmichael’s retirement, Mr. Blakely was
appointed Chairman of the CNG Committee. Mr. Gordy joined the CNG Committee effective December 17,
2013. 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 28, 2014, 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) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Western Bridgeport, Inc.(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nick Carter(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dwight L. Dunlap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyatt L. Hogan(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin F. Wall(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dennis F. Coker . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kevin J. Craig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
David M. Hartz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kenneth Hudson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathy H. Roberts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kathryn S. Wilson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gregory F. Wooten . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert T. Blakely . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Russell D. Gordy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Donald R. Holcomb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert B. Karn III (8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Richard A. Navarre . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S. Reed Morian(9)
Corbin J. Robertson III (10) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stephen P. Smith . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leo A. Vecellio, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Directors and Officers as a Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common
Units
24,075,925
17,279,860
5,627,120
24,210
20,836
5,000
4,000
1,500
10,000
1,140
8,000
13,000
—
—
22,500
70,000
120,134
5,634
—
6,141,588
1,564,698
3,552
20,000
32,111,716
Percentage of
Common
Units(1)
21.9%
15.7%
5.1%
*
*
*
*
*
*
*
*
*
—
—
*
*
*
*
—
5.6%
1.4%
*
*
29.2%
*
Less than one percent.
(1) Percentages based upon 109,812,408 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.
(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) These common units may be deemed to be beneficially owned by Mr. Robertson. The address of Western
Bridgeport is 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
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(5)
Includes 210 common units held by Mr. Carter’s spouse.
(6) 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.
(7)
(8)
Includes 500 common units held by Mr. Wall’s daughter. Mr. Wall disclaims beneficial ownership of these
securities.
Includes 317 common units held by the Payton Grace Portnoy Irrevocable Trust and 317 common units held
by the Blake Kristopher Portnoy Irrevocable Trust. Mr. Karn is the trustee of each of these trusts for his
grandchildren, but disclaims beneficial ownership of these securities.
(9) 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.
(10) Mr. Robertson may be deemed to beneficially own 26,231 common units held CIII Capital Management,
LLC, 50,461 common units held by The Corbin James Robertson III 2009 Family Trust and 397 common
units held by his spouse, Brooke Robertson. The address for CIII Capital Management, LLC 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: 1,291,638 common units owned directly by Mr. Robertson and 1,000 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent
Acquisitions” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations —
Related Party Transactions — 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.
In January 2013, NRP sold 3,784,572 common units representing limited partnership interest in NRP in a
private placement, including 756,914 common units to Cutlass Collieries LLC. Mr. Holcomb indirectly owned
1% of Cutlass Collieries LLC at the time of the private placement. Subsequent to the private placement, Cutlass
Collieries distributed all of its units to its members, including a company owned by Mr. Holcomb.
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. Mr. Fifield served as an Adena designee until his resignation from the Board in
October 2013. Effective October 31, 2013, Mr. Holcomb was appointed by Adena to replace Mr. Fifield. Adena
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will also have the right, pursuant to the terms of the Investor Rights Agreement, to withhold its consent to the
sale or other disposition of any entity or assets contributed by Cline affiliates to NRP, and any such sale or
disposition will be void without Adena’s consent.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private
equity funds focused on investments in the energy business. NRP’s Board of Directors has adopted a formal
conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by
Quintana Capital. The basic tenets of the policy are set forth below.
NRP’s business strategy has historically focused on:
• The ownership of natural resource properties in North America, including, but not limited to coal,
aggregates and industrial minerals, and oil and gas. NRP leases these properties to mining or operating
companies that mine or produce the resources and pay NRP a royalty.
• The ownership and operation of transportation, storage and related logistics activities related to extracted
hard minerals.
The businesses and investments described in this paragraph are referred to as the “NRP Businesses.”
NRP’s acquisition strategy also includes:
• The ownership of non-operating working interests in oil and gas leases.
• The ownership of non-controlling equity interests in companies involved in natural resource development
and extraction.
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.
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• NRP will undertake to advise Quintana Capital of its decision regarding a potential investment
opportunity within 10 business days of the identification of such opportunity to the Conflicts Committee.
If the opportunity relates to the acquisition of a Shared Business, NRP and Quintana Capital will adhere to
the following procedures:
• If the opportunity is generated by individuals other than Mr. Robertson, the opportunity will belong to the
entity for which those individuals are working.
• If the opportunity is generated by Mr. Robertson and both NRP and Quintana Capital are interested in
pursuing the opportunity, it is expected that the Conflicts Committee will work together with the relevant
Limited Partner Advisory Committees for Quintana Capital to reach an equitable resolution of the
conflict, which may involve investments by both parties.
In all cases above in which Mr. Robertson has a conflict of interest, investment decisions will be made on
behalf of NRP by the Conflicts Committee and on behalf of Quintana Capital Group by the relevant Investment
Committee, with Mr. Robertson abstaining.
For a portion of 2013, a fund controlled by Quintana Capital owned a significant membership interest in
Taggart Global, including the right to nominate two members of Taggart’s five-person board of directors. In July
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 are based on the sales price
for the coal that is processed through the facilities.
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, has been named Chairman of the Board of Corsa.
For more information on our relationship with Forge and Corsa Coal, see “Management’s Discussion and
Analysis of Financial Condition and Results of Operations — Related Party Transactions — Quintana Capital
Group, 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
116
such resolution. The partnership agreement contains provisions that allow our general partner to take into account
the interests of other parties in addition to our interests when resolving conflicts of interest.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to
us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution
is considered to be fair and reasonable to us if that resolution is:
• approved by the conflicts committee, although our general partner is not obligated to seek such approval
and our general partner may adopt a resolution or course of action that has not received approval;
• on terms no less favorable to us than those generally being provided to or available from unrelated third
parties; or
• fair to us, taking into account the totality of the relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous to us.
In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is
specifically provided for in the partnership agreement, consider:
• the relative interests of any party to such conflict and the benefits and burdens relating to such interest;
• any customary or accepted industry practices or historical dealings with a particular person or entity;
• generally accepted accounting practices or principles; and
• such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under
the circumstances.
Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to
unitholders.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general
partner regarding such matters as:
•
•
•
•
•
amount and timing of asset purchases and sales;
cash expenditures;
borrowings;
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
117
activities of their own in which we have no economic interest. If these separate activities are significantly greater
than our activities, there could be material competition for the time and effort of the officers and employees who
provide services to our general partner. The officers of GP Natural Resource Partners LLC are not required to
work full time on our affairs. These officers devote significant time to the affairs of the WPP Group or its
affiliates and are compensated by these affiliates for the services rendered to them.
We reimburse our general partner and its affiliates for expenses.
We reimburse our general partner and its affiliates for costs incurred in managing and operating us,
including costs incurred in rendering corporate staff and support services to us. The partnership agreement
provides that our general partner determines the expenses that are allocable to us in any reasonable manner
determined by our general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has
recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides
that any action taken by our general partner to limit its liability or our liability is not a breach of our general
partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on
liability.
Common unitholders have no right to enforce obligations of our general partner and its affiliates under
agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not
grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and
its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the
result of arm’s-length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered
to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also
enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership
agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our
general partner and its affiliates, on the other, are the result of arm’s-length negotiations.
All of these transactions entered into after our initial public offering are on terms that are fair and reasonable
to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our
general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with
that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
We may not choose to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent auditors and others who have performed services for us in the past were retained
by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates
and us. Attorneys, independent auditors and others who perform services for us are selected by our general
partner or the conflicts committee and may also perform services for our general partner and its affiliates. We
may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest
arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on
the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has
not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
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Our general partner’s affiliates may compete with us.
The partnership agreement provides that our general partner is restricted from engaging in any business
activities other than those incidental to its ownership of interests in us. Except as provided in our partnership
agreement, 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.
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,
2013, there were no transactions where such guidelines were not followed.
Item 14.
Principal Accounting 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 2013 and 2012. All of
our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board of
Directors. The following table presents fees for professional services rendered by Ernst &Young LLP:
Audit Fees(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-Related Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax Fees(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All Other Fees(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$753,502
—
654,776
1,995
$495,169
—
580,529
1,900
2013
2012
(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; 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.
119
Audit and Non-Audit Services Pre-Approval Policy
I. Statement of Principles
Under the Sarbanes-Oxley Act of 2002 (the “Act”), the Audit Committee of the Board of Directors is
responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of
this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by
the independent auditor in order to assure that they do not impair the auditor’s independence from the
Partnership. To implement these provisions of the Act, the SEC has issued rules specifying the types of services
that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of
the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of
Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the “Policy”), which sets forth the
procedures and the conditions pursuant to which services proposed to be performed by the independent auditor
may be pre-approved.
The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to
be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case
services by the Audit Committee (“general pre-approval”) or require the specific pre-approval of the Audit
Committee (“specific pre-approval”). The Audit Committee believes that the combination of these two
approaches in this Policy will result in an effective and efficient procedure to pre-approve services performed by
the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it
will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any
proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-
approval by the Audit Committee.
For both types of pre-approval, the Audit Committee will consider whether such services are consistent with
the SEC’s rules on auditor independence. The Audit Committee will also consider whether the independent
auditor is best positioned to provide the most effective and efficient service for reasons such as its familiarity
with our business, employees, culture, accounting systems, risk profile and other factors, and whether the service
might enhance the Partnership’s ability to manage or control risk or improve audit quality. All such factors will
be considered as a whole, and no one factor will necessarily be determinative.
The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in
deciding whether to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio
between the total amount of fees for audit, audit-related and tax services.
The appendices to this Policy describe the audit, audit-related and tax services that have the general pre-
approval of the Audit Committee. The term of any general pre-approval is 12 months from the date of pre-
approval, unless the Audit Committee considers a different period and states otherwise. The Audit Committee
will annually review and pre-approve the services that may be provided by the independent auditor without
obtaining specific pre-approval from the Audit Committee. The Audit Committee will add or subtract to the list
of general pre-approved services from time to time, based on subsequent determinations.
The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its
responsibilities. It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by
the independent auditor to management.
Ernst & Young LLP, our independent auditor has reviewed this Policy and believes that implementation of
the policy will not adversely affect its independence.
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.
120
III. Audit Services
The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the
Audit Committee. Audit services include the annual financial statement audit (including required quarterly
reviews), subsidiary audits and other procedures required to be performed by the independent auditor to be able
to form an opinion on the Partnership’s consolidated financial statements. These other procedures include
information systems and procedural reviews and testing performed in order to understand and place reliance on
the systems of internal control, and consultations relating to the audit or quarterly review. Audit services also
include the attestation engagement for the independent auditor’s report on management’s report on internal
controls for financial reporting. The Audit Committee monitors the audit services engagement as necessary, but
not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting
from changes in audit scope, partnership structure or other items.
In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee
may grant general pre-approval to other audit services, which are those services that only the independent auditor
reasonably can provide. Other audit services may include statutory audits or financial audits for our subsidiaries
or our affiliates and services associated with SEC registration statements, periodic reports and other documents
filed with the SEC or other documents issued in connection with securities offerings.
IV. Audit-related Services
Audit-related services are assurance and related services that are reasonably related to the performance of
the audit or review of the Partnership’s financial statements or that are traditionally performed by the
independent auditor. Because the Audit Committee believes that the provision of audit-related services does not
impair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit
Committee may grant general pre-approval to audit-related services. Audit-related services include, among
others, due diligence services pertaining to potential business acquisitions/dispositions; accounting consultations
related to accounting, financial reporting or disclosure matters not classified as “Audit Services”; assistance with
understanding and implementing new accounting and financial reporting guidance from rulemaking authorities;
financial audits of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/
or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and
assistance with internal control reporting requirements.
V. Tax Services
The Audit Committee believes that the independent auditor can provide tax services to the Partnership such
as tax compliance, tax planning and tax advice without impairing the auditor’s independence, and the SEC has
stated that the independent auditor may provide such services. Hence, the Audit Committee believes it may grant
general pre-approval to those tax services that have historically been provided by the auditor, that the Audit
Committee has reviewed and believes would not impair the independence of the auditor and that are consistent
with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of the
independent auditor in connection with a transaction initially recommended by the independent auditor, the sole
business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the
Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial
Officer or outside counsel to determine that the tax planning and reporting positions are consistent with this
Policy.
VI. Pre-Approval Fee Levels or Budgeted Amounts
Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will
be established annually by the Audit Committee. Any proposed services exceeding these levels or amounts will
require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overall
relationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For
each fiscal year, the Audit Committee may determine the appropriate ratio between the total amount of fees for
audit, audit-related and tax services.
121
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.
122
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) Exhibits
Exhibit
Number
Description
2.1 — 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 the Current Report on Form 8-K filed on January 25, 2013).
3.1 — 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 the 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 the 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 the Current
Report on Form 8-K filed on October 31, 2013).
3.4 — 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 the Annual Report on Form 10-K for
the year ended December 31, 2002).
3.5 — 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 the Current Report on
Form 8-K filed June 23, 2003).
4.2 — 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 the Current Report on Form 8-K filed on July 20, 2005).
4.3 — 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 the Current Report on Form 8-K filed on March 29, 2007).
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 the 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 the
Current Report on Form 8-K filed on March 29, 2007).
4.6 — 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 the Current
Report on Form 8-K filed on March 26, 2009).
123
Exhibit
Number
Description
4.7 — 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 the 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 the 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 the 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 the 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 the 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 the 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 the 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 the 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 the 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 the 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 the 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 May 4, 2012).
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 — Registration Rights Agreement, dated September 18, 2013, by and among Natural Resource Partners
L.P., NRP Finance Corporation and Citigroup Global Markets Inc., as representative of the several
initial purchasers (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed on
September 19, 2013).
124
Exhibit
Number
Description
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 the 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 the 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 the
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 the 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 the 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 the Current Report on Form 8-K filed on January 4, 2007).
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).
125
Exhibit
Number
Description
10.14 — First Amendment to Term Loan Agreement, dated as of June 7, 2013 (incorporated by reference to
Current Report on Form 8-K filed on June 10, 2013).
10.15 — Third Amended and Restated Agreement of Limited Partnership of OCI Wyoming, L.P., dated
September 18, 2013 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed
by OCI Resources LP on September 18, 2013).
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, 2012).
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 Current Report on Form 8-K
filed on December 20, 2013).
10.18 — Purchase Agreement dated September 13, 2013 by and among Natural Resource Partners L.P., NRP
Finance Corporation and Citigroup Global Markets Inc. (as the representative of the several initial
purchasers) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on
September 17, 2013).
10.19 — 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).
21.1* — List of subsidiaries of Natural Resource Partners L.P.
23.1* — Consent of Ernst & Young LLP.
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.
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).
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, 2012, 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
126
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 28, 2014
Date: February 28, 2014
Date: February 28, 2014
By:
/s/ CORBIN J. ROBERTSON, JR.
Corbin J. Robertson, Jr.,
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
By:
/s/ DWIGHT L. DUNLAP
Dwight L. Dunlap,
Chief Financial Officer and
Treasurer
(Principal Financial Officer)
By:
/s/ KENNETH HUDSON
Kenneth Hudson
Controller
(Principal Accounting Officer)
127
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 28, 2014
Date: February 28, 2014
Date: February 28, 2014
Date: February 28, 2014
Date: February 28, 2014
Date: February 28, 2014
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
128
Date: February 28, 2014
Date: February 28, 2014
Date: February 28, 2014
/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
129
Exhibit 31.1
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.
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 28, 2014
By: /s/ Corbin J. Robertson, Jr.
Corbin J. Robertson, Jr.
Chief Executive Officer
Exhibit 31.2
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
I, Dwight L. Dunlap, certify that:
1)
I have reviewed this report on Form 10-K of Natural Resource Partners L.P.
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.
By: /s/ Dwight L. Dunlap
Dwight L. Dunlap
Chief Financial Officer and Treasurer
Date: February 28, 2014
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, 2013 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. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
Date: February 28, 2014
/s/ Corbin J. Robertson, Jr.
Name: Corbin J. Robertson, Jr.
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, 2013 filed with
the Securities and Exchange Commission on the date hereof (the “Report”), I, Dwight L. Dunlap, 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. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
4. The information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
Date: February 28, 2014
/s/ Dwight L. Dunlap
Name: Dwight L. Dunlap
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Unitholder Information
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
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 Street, 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, projected quantities of future production by our
lessees producing from our reserves, and projected demand or supply for coal, trona,
soda ash, aggregates and industrial minerals, 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.
NATURAL RESOURCE
PARTNERS L.P.
601 Jefferson Street
Suite 3600
Houston, TX 77002
www.nrplp.com