NATURAL RESOURCE PARTNERS LP - Annual Report: 2013 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2013 or

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)

(713) 751-7507

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

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  x        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  x

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  x        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  x        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.

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2)    Yes  ¨        No  x

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.

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Forward-Looking Statements

Statements included in this Annual Report on Form 10-K may constitute forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements.

Such forward-looking statements include, among other things, statements regarding:

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.

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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.

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.

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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.

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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:

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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

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.

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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

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:

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.

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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.

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The map below shows the location of our properties in Northern Appalachia.

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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.

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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.

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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.

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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.”

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The map below shows the location of our properties in the Illinois Basin.

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Northern Powder River Basin

Western Energy.     The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 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.

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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

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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.

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.

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.

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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:

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.

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The map below illustrates the location of BRP’s current mineral rights.

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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.

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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.

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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,

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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

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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

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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.

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:

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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:

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:

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:

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:

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

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:

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:

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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:

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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:

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:

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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.

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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

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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

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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.

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None.

The information required by this Item is included under Item 1, “Business” and incorporated by reference herein.

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.

Not applicable.

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PART II

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.

Cash Distributions to Partners

(In thousands)

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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)

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.

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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”

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.

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Reconciliation of “Net income” to “EBITDA”