10-K 1 d263444d10k.htm FORM 10-K Form 10-K
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 

 

  þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011 or

 

  ¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     

Commission file number: 1-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

 

Delaware   35-2164875
(State or other jurisdiction of
incorporation or organization)
 

(I.R.S. Employer

Identification Number)

601 Jefferson, Suite 3600
Houston, Texas

(Address of principal executive offices)

 

77002

(Zip Code)

(713) 751-7507

(Registrant’s telephone number, including area code)

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

 

Title of each class

 

Name of each exchange on which registered

Common Units representing limited partnership interests   New York Stock Exchange

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

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ        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  þ

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  þ        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  þ        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.    þ

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.

 

þ  Large Accelerated Filer      ¨  Accelerated Filer   ¨  Non-accelerated Filer   ¨  Smaller Reporting Company

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

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 $1.9 billion on June 30, 2011 based on a price of $33.17 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 29, 2012, there were 106,027,836 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE.

None.

 

 

 


Table of Contents

Table of Contents

 

Item

       Page  
  PART I   
 

1.

  Business      2   
 

1A.

  Risk Factors      12   
 

1B.

  Unresolved Staff Comments      22   
 

2.

  Properties      23   
 

3.

  Legal Proceedings      33   
 

4.

  Mine Safety Disclosures      33   
  PART II   
 

5.

  Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities      34   
 

6.

  Selected Financial Data      35   
 

7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      36   
 

7A.

  Quantitative and Qualitative Disclosures About Market Risk      51   
 

8.

  Financial Statements and Supplementary Data      52   
 

9.

  Changes In and Disagreements with Accountants on Accounting and Financial Disclosure      74   
 

9A.

  Controls and Procedures      74   
 

9B.

  Other Information      75   
  PART III   
 

10.

  Directors and Executive Officers of the General Partner and Corporate Governance      76   
 

11.

  Executive Compensation      82   
 

12.

  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters      90   
 

13.

  Certain Relationships and Related Transactions, and Director Independence      91   
 

14.

  Principal Accounting Fees and Services      97   
  PART IV   
 

15.

  Exhibits, Financial Statement Schedules      101   


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Forward-Looking Statements

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

Such forward-looking statements include, among other things, statements regarding capital expenditures and acquisitions, expected commencement dates of mining, projected quantities of future production by our lessees producing from our reserves, and projected demand or supply for coal, aggregates and oil and gas that will affect sales levels, prices and royalties realized by us.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

You should not put undue reliance on any forward-looking statements. Please read “Item 1A. Risk Factors” for important factors that could cause our actual results of operations or our actual financial condition to differ.

 

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PART I

 

Item 1. Business

Natural Resource Partners L.P. is 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, 2011, we owned or controlled approximately 2.3 billion tons of proven and probable coal reserves, and we also owned approximately 380 million tons of aggregate reserves in a number of states across the country. 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. Our lessees are generally required to make payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton, in addition to minimum payments.

In 2011, our lessees produced 49.2 million tons of coal from our properties and our coal royalty revenues were $279.2 million. Processing fees and transportation fees added $30.2 million to our total revenues. In addition, we received $14.0 million in oil and gas royalties, and our lessees produced 5.9 million tons of aggregates resulting in aggregate royalties of $6.7 million.

Partnership Structure and Management

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through a wholly owned operating company, NRP (Operating) 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 nine 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 operating mines, but instead enter into leases with mine operators granting them the right to mine and sell reserves from our property in exchange for a royalty payment. A typical lease has a 5- to 10-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 has been submitted to us is accurate. Our audit and inspection processes are designed to

 

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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 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 receive minimum royalties with respect to our oil and gas properties, but do typically receive bonus payments at the time of execution of the lease.

Because we do not operate any mines, we do not bear ordinary operating costs and have 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 and then are reimbursed by the lessee for the taxes on their leased property, pursuant to the terms of the lease.

Our business is not seasonal, although at times severe or abnormal weather can cause a short-term decrease in production by our lessees due to the weather’s negative impact on production and transportation.

Acquisitions

We are a growth-oriented company and have completed a number of acquisitions over the last several years. For a discussion of our recent acquisitions, please see “Recent Acquisitions” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Coal Royalty Revenues, Reserves and Production

The following 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, 2011, 2010 and 2009. Coal royalty revenues were generated from the properties in each of the areas as follows:

 

     Coal Royalty Revenues
For the Years Ended
December 31,
     Average Coal Royalty
Revenue Per Ton
For the Years Ended
December 31,
 
     2011      2010      2009      2011      2010      2009  
     (In thousands)      ($ per ton)  

Area

                 

Appalachia

                 

Northern

   $ 20,578       $ 18,676       $ 14,959       $ 3.92       $ 3.81       $ 3.03   

Central

     196,789         144,934         132,543         6.66         5.36         4.73   

Southern

     11,717         19,405         19,382         6.91         6.87         6.00   
  

 

 

    

 

 

    

 

 

          

Total Appalachia

     229,084         183,015         166,884         6.28         5.26         4.61   

Illinois Basin

     41,324         30,210         22,019         4.38         3.90         3.31   

Northern Powder River Basin

     7,658         8,444         7,718         2.86         1.89         1.94   

Gulf Coast

     1,155         92                 2.21         1.77           
  

 

 

    

 

 

    

 

 

          

Total

   $ 279,221       $ 221,761       $ 196,621       $ 5.68       $ 4.71       $ 4.20   
  

 

 

    

 

 

    

 

 

          

 

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The following table sets forth production data and reserve information for the properties that we owned or controlled for the years ending December 31, 2011, 2010 and 2009. All of the reserves reported below are recoverable reserves as determined by 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:

Production and Reserves

 

      Production for the Year Ended 
December 31,
     Proven and Probable Reserves at
December 31, 2011
 
         2011              2010              2009          Underground      Surface      Total  
     (Tons in thousands)  

Area

                 

Appalachia

                 

Northern

     5,251         4,900         4,943         488,444         6,019         494,463   

Central

     29,555         27,056         28,032         1,054,129         226,829         1,280,958   

Southern

     1,695         2,824         3,233         98,127         25,340         123,467   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Appalachia

     36,501         34,780         36,208         1,640,700         258,188         1,898,888   

Illinois Basin

     9,445         7,753         6,656         262,284         14,143         276,427   

Northern Powder River Basin

     2,682         4,467         3,984                 102,158         102,158   

Gulf Coast(1)

     523         52                                   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     49,151         47,052         46,848         1,902,984         374,489         2,277,473   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes lignite acquired in the BRP acquisition. Due to the number of mineral acres involved in the BRP transaction, we have not completed an analysis of the reserve quantity and quality for each mineral that was acquired. As a result, the reserves held by BRP are not included in the statistical information in this Form 10-K. We plan to complete a review of the BRP reserves by the end of 2012.

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, 2011, approximately 51% of our reserves were low sulfur coal and 34% 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, and we own steam coal reserves in the Illinois Basin and the Northern Powder River Basin. In 2011, approximately 34% of the production and 45% 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, 2011.

Sulfur Content, Typical Quality and Type of Coal

 

          Sulfur Content              
          Low     Medium     High           Typical Quality              
    Compliance     (less than     (1.0% to     (greater           Heat Content     Sulfur     Type of Coal  

Area

  Coal(1)     1.0%)     1.5%)     than 1.5%)     Total     (Btu per pound)     (%)     Steam     Metallurgical(2)  
    (Tons in thousands)           (Tons in thousands)  

Appalachia

                 

Northern

    40,048        48,615        20,708        425,140        494,463        12,879        2.73        484,901        9,562   

Central

    648,486        910,843        318,396        51,719        1,280,958        13,272        0.89        884,103        396,855   

Southern

    85,654        91,743        28,209        3,515        123,467        13,506        0.82        80,396        43,071   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Total Appalachia

    774,188        1,051,201        367,313        480,374        1,898,888        13,185        1.36        1,449,400        449,488   

Illinois Basin

                  2,334        274,093        276,427        11,518        3.12        276,427          

Northern Powder River Basin

           102,158                      102,158        8,800        0.65        102,158          

Gulf Coast(3)

                                                              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Total

    774,188        1,153,359        369,647        754,467        2,277,473            1,827,985        449,488   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

 

 

(1) Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the Clean Air Act without blending with other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal.

 

(2) For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the metallurgical category can also be used as steam coal.

 

(3) Includes lignite acquired in the BRP acquisition. Due to the number of mineral acres involved in the BRP transaction, we have not completed an analysis of the reserve quantity and quality for each mineral that was acquired. As a result, the reserves held by BRP are not included in the statistical information in this Form 10-K. We plan to complete a review of the BRP reserves by the end of 2012.

We have engaged outside consultants to conduct reserve studies of our existing properties. These studies are an ongoing process and we will update the reserve studies based on our review of the following factors: the size of the properties, the amount of production that has occurred, or the development of new data which may be used in these studies. In connection with most acquisitions, we have either commissioned new studies or relied on recent reserve studies completed prior to the acquisition. In addition to these studies, we base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. Some of these factors and assumptions include:

 

   

future coal prices, mining economics, capital expenditures, severance and excise taxes, and development and reclamation costs;

 

   

future mining technology improvements;

 

   

the effects of regulation by governmental agencies; and

 

   

geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in other areas of our reserves.

 

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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.

Transportation and Processing Revenues

We own preparation plants and related material handling facilities. Similar to our royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the material that is processed. These facilities generated $13.5 million in processing revenues for 2011.

In addition to our preparation plants, we own handling and transportation infrastructure. For the year ended December 31, 2011, we recognized $16.7 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 Shay No. 1 mine in Illinois, which we lease to a Cline affiliate, we operate the coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties.

Aggregates Royalty Revenues, Reserves and Production

We own and manage aggregate reserves, but do not engage in the mining, processing or sale of aggregate related products. We own an estimated 380 million tons of aggregate reserves located in a number of states across the country. During 2011, our lessees produced 5.9 million tons of aggregates, and our aggregate royalties were $6.7 million.

Oil and Gas Properties

We generated $14.0 million, or 4% of our total revenues, from approximately 250,000 net leased oil and gas mineral acres in 2011. Our oil and gas royalty revenue is primarily derived from lease bonus payments, oil and gas royalty interests and overriding royalty interests paid to us from the lessees. We have leased our mineral interests to third parties for the exploration and production of oil and gas, principally in the Appalachian Basin, Louisiana and Oklahoma. When we lease our mineral interests, we may negotiate a lease bonus payment and retain a royalty interest. We are not an operator with respect to any of the oil and gas activities on our properties. In addition to our leased acres, a large portion of our mineral acres contain yet undetermined commercial potential and are available to be leased and may contribute revenue in the future.

Significant Customers

In 2011, we had total revenues of $107.3 million from Alpha Natural Resources and $64.8 million from The Cline Group. 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 Cline’s Williamson mine 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.

 

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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 and comprehensive 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.

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, depending on the requirements of individual state and regional implementation plans, could make coal a less attractive 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.

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 stayed by order of the D.C. Circuit on December 30, 2011, pending resolution of legal challenges to the final rule. Those challenges are not expected to be resolved until mid-2012 at the earliest. In the meantime, all state regulations that were based on the CAIR are still in effect. We are unable to predict whether the CSAPR program will be upheld or reversed and, therefore, unable to predict any effect on NRP.

 

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In June 2005, the 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 December 23, 2011, 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. That rule has not yet been published, and the EPA’s plans to do so in light of the stay of the CSAPR have yet to be announced.

On December 16, 2011, the EPA Administrator signed the “Mercury and Air Toxics Rule,” which will impose limits on the hazardous air pollutant emissions allowed for the nation’s existing and future coal-fueled generation fleet. The limits imposed by those rules may limit demand for or otherwise restrict sales of our lessees’ coal, which would reduce royalty 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 June 22, 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-fueled 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, 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 asserted, and Congress is considering legislation to delay or repeal the EPA’s actions, but we cannot predict the outcome of these efforts. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act. The EPA recently adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which requires permits for emissions of GHGs from many stationary sources, including coal-fired electric power plants, effective January 2, 2011. The 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. As a result of revisions to its preconstruction permitting rules that became fully effective on January 2, 2011, the 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 alternatives fuels and generation systems, as well as increase litigation risk for — and so discourage development of — coal-fired power plants.

In addition, the EPA is under a consent decree which required it to propose by July 2011 and take final action by May 2012 on “new source performance standards” to govern GHG emissions from electric generating units, certainly including those fired by coal. The decree also represents the EPA’s agreement to consider adopting a GHG limitation program governing existing sources, as well, which the EPA may attempt to use to establish a cap-and-trade-like system on emissions of power plants’ GHG emissions. The EPA has missed the deadline for proposal: as of early November 2011, the EPA had drafted proposed rules, but that proposal is pending review at the Office of Management and Budget, and is not yet public. The EPA’s failure to propose rules by the required date will delay final action, as well.

 

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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, and require mine operators to post performance bonds to ensure compliance with any reclamation obligations. 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.

Some 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 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.

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 §402 of the statute administered by the states and the EPA for regulating the concentrations of pollutants in discharges of waste and storm water; and the §404 program administered by the Army Corps of Engineers for regulating 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 wetland. The unpermitted discharge of pollutants into such waters from a spill or leak is prohibited. The Clean Water Act and regulations implemented under §404 also prohibit discharges of fill material and certain other activities in waters unless authorized by an appropriately issued permit.

Our lessees generally obtain “individual l” 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 the application. Small underground coal mines that must construct fills as part of their mining

 

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operations may qualify for another version of the §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 royalty 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 §404 fill permits by the Corps and §402 NPDES permits by state agencies. These policies, among other things, seek to impose limits on a 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 the subject to challenge in federal district court in Washington, D.C. in National Mining Association v. Jackson. That district court recently denied a request by the National Mining Association (NMA) for a preliminary injunction after concluding that industry had not shown sufficient concrete harm to warrant the injunction. However, the court rejected the EPA’s motion to dismiss the complaint and determined that NMA is likely to prevail on its claims that the EPA’s policies constitute unlawful rulemaking and fall outside of the EPA’s statutory authority.

Notwithstanding the outcome of this suit, environmental groups have issued “Notices of Intent to Sue (NOIs)” to companies that own coal and other minerals and lease them for mining. The NOI is a notification required by the Clean Water Act before an individual is allowed to file a suit in federal court. To date, no civil actions are known to have been filed against land companies.

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.

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 $0.07/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. In The West Virginia Highlands Conservancy v. Kenneth Salazar, Secretary of the Department of the Interior, et al., and the West Virginia Coal Association, (United States District Court for the Southern District of West Virginia), an environmental group claims that the SRF is underfunded and that the Federal Office of Surface Mining (OSM) has an obligation under SMCRA to ensure that the SRF funds are increased to cover the supposed shortfall. On March 23, 2007, the plaintiff moved to reopen this long inactive case on the grounds that a recommendation of the state’s “Special Reclamation Fund Advisory Council” (SRFAC) regarding the establishment of a $175 million trust fund for water treatment at future bond forfeiture sites has not been approved. In a May 15, 2008 Order, the court denied plaintiffs motion to reopen without prejudice, denied the plaintiff’s motion to defer, except insofar as it sought denial of the motion to reopen without prejudice, and retained the case on the inactive docket of the court. On March 15, 2011, the Plaintiff filed a Second Motion to Reopen. This motion was based on the 2011 Legislature’s failure to adopt the recommendations of the SRFAC issued in December 2010 that the SRF tax be increased to 25.69 cents per ton. The Second Motion to Reopen has been briefed by all sides and is waiting decision by the Court.

In two companion cases, West Virginia Highlands Conservancy v. Huffman, (United States District Court, Northern District of West Virginia), and West Virginia Highlands Conservancy v. Huffman, (Southern District of West Virginia) the courts have granted summary judgment and required the West Virginia Department of Environmental Protection (WVDEP) to obtain NPDES permits for bond forfeiture sites. The WVDEP, joined by other states appealed the decision of the Northern District Court to the Fourth Circuit. By ruling of November 8, 2010, the Fourth Circuit affirmed the district court’s opinion. Following that decision, the WVDEP chose not to appeal the decision of the Southern District Court.

 

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On August 2, 2011, the West Virginia Highlands Conservancy and other environmental groups filed actions against WVDEP claiming that WVDEP was required to obtain NPDES permits with water quality based effluent limits for 171 bond forfeiture sites not included in the original cases. One action was filed in the Southern District of West Virginia and one in the Northern District. With each action, a Consent Decree executed by the Plaintiffs and WVDEP was filed. The Consent Decrees obligate WVDEP to obtain NPDES permits with water quality based effluent limitations for all sites at issue over the next four years. The decrees also require WVDEP to prepare and submit to the plaintiffs and the SRFAC a report showing the capital, and operation and maintenance costs anticipated to be incurred in complying with the Consent Decrees. Although neither court has yet entered the agreed upon Consent Decrees, WVDEP has proceeded as if both decrees have been entered and has proceeded to obtain the first group of NPDES permits. In addition, an estimate has been prepared of the additional capital and maintenance costs required for water treatment obligations imposed by the requirement for NPDES permits. As a result of these increased costs, the SRFAC has recommended an increase in the special reclamation tax from 14.4¢ per ton to 27.9¢ per ton. This recommendation has been forwarded to the 2012 Legislature for its consideration. As a result of these actions to require the State to increase the money in the SRF, our lessees could be forced to bear an increase in the tax on mined coal to increase the size of the SRF. This could impair their ability to economically mine the coal that has been leased to them.

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. In January 2006, West Virginia passed a law imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. Similarly, on April 27, 2006, the Governor of Kentucky signed mine safety legislation that includes requirements for increased inspections of underground mines and additional mine safety equipment and authorizes the assessment of penalties of up to $5,000 per incident for violations of mine ventilation or roof control requirements.

On June 15, 2006, President Bush signed new mining safety legislation that mandates similar improvements in mine safety practices; increases civil and criminal penalties for non-compliance; requires the creation of additional mine rescue teams; and expands the scope of federal oversight, inspection and enforcement activities. Earlier, the federal Mine Safety and Health Administration (MSHA) announced the promulgation of new emergency rules on mine safety that took effect immediately upon their publication in the Federal Register on March 9, 2006. These rules address mine safety equipment, training, and emergency reporting requirements.

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.

 

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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. Typically, our lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. In the past, our lessees have generally obtained their mining permits without significant delay. 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.

Employees and Labor Relations

We do not have any employees. To carry out our operations, affiliates of our general partner employ approximately 75 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, aggregate, oil and gas and timber as well as related transportation and processing infrastructure revenues.

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 (Exchange Act) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (SEC). 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 and 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 Corporate Governance Guidelines and our committee charters will be made available upon written request.

 

Item 1A. Risk Factors

Risks Related to Our Business

A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our reserves.

The prices our lessees receive for their coal depend upon factors beyond their or our control, including:

 

   

the supply of and demand for domestic and foreign coal;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the price and availability of alternative fuels, especially natural gas;

 

   

the demand for steel;

 

   

the proximity to and capacity of transportation facilities;

 

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weather conditions; and

 

   

the effect of worldwide energy conservation measures.

Natural gas is the primary fuel that competes with steam coal for power generation. Recently, natural gas prices have dropped below $2.50/Mcf, 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. A substantial or extended decline in coal prices could materially and adversely affect us in two ways. First, lower prices may reduce the quantity of coal that may be economically produced from our properties. This, in turn, could reduce our coal royalty revenues and the value of our coal reserves. Second, even if production is not reduced, the royalties we receive on each ton of coal sold may be reduced.

Our lessees’ mining operations are subject to operating risks that could result in lower royalty revenues to us.

Our royalty revenues are largely dependent on our lessees’ level of production from our mineral reserves. The level of our lessees’ production is subject to operating conditions or events beyond their or our control including:

 

   

the inability to acquire necessary permits or mining or surface rights;

 

   

changes or variations in geologic conditions, such as the thickness of the mineral deposits and, in the case of coal, the amount of rock embedded in or overlying the coal deposit;

 

   

the price of natural gas, which is a competing fuel in the generation of electricity;

 

   

changes in governmental regulation and enforcement policy related to the coal industry or the electric utility industry;

 

   

mining and processing equipment failures and unexpected maintenance problems;

 

   

interruptions due to transportation delays;

 

   

adverse weather and natural disasters, such as heavy rains and flooding;

 

   

labor-related interruptions; and

 

   

fires and explosions.

Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our lessees are pursued for these sanctions, costs and liabilities, their mining operations and, as a result, our royalty revenues could be adversely affected.

The regulatory climate in Central Appalachia has made it much more difficult for our lessees to obtain permits to mine our coal. The impact of the regulations has been to increase both the cost to our lessees of acquiring permits and the time that it will take for them to receive the permits. These conditions have increased our lessees’ cost of mining and delayed or halted production at particular mines for varying lengths of time or permanently. Any interruptions to the production of coal from our reserves would reduce our coal royalty revenues.

Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues.

Our lessees produce a significant amount of the metallurgical coal that is used in both the U.S. and foreign steel industries. In 2011, approximately 34% of the coal production and 45% of the coal royalty revenues from our properties were from metallurgical coal. Since the amount of steel that is produced is tied to global economic conditions, a decline in those conditions could result in the decline of steel, coke and metallurgical coal production. 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.

 

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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 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 asserted, and Congress is considering legislation to delay or repeal the EPA’s actions, but we cannot predict the outcome of these efforts. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGS under existing provisions of the Clean Air Act. The EPA recently adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHG from motor vehicles and the other of which requires permits for emissions of GHGs from many stationary sources, including coal-fired electric power plants, effective January 2, 2011. The 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. As a result of revisions to its preconstruction permitting rules that became fully effective on January 2, 2011, the 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 alternatives fuels and generation systems, as well as increase litigation risk for — and so discourage development of — coal-fired power plants.

In addition, the EPA is under a consent decree which required it to propose by July 2011 and take final action by May 2012 on “new source performance standards” to govern GHG emissions from electric generating units, certainly including those fired by coal. The decree also represents the EPA’s agreement to consider adopting a GHG limitation program governing existing sources, as well, which the EPA may attempt to use to establish a cap-and-trade-like system on emissions of power plants’ GHG emissions. The EPA has missed the deadline for proposal: As of early November 2011, the EPA had drafted proposed rules, but that proposal is pending review at the Office of Management and Budget, and is not yet public. The EPA’s failure to propose rules by the required date will delay final action, as well.

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.

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. 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 lessees’ operations.

New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements, could further regulate or tax the mineral industry and may also require our lessees to change their operations significantly, to incur increased costs or to obtain new or

 

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different permits, any of which could decrease our royalty revenues. Such increased scrutiny and enforcement of our lessees’ operations may result in increased compliance costs, revisions to permits, or changes in operations, which could decrease our royalty revenues.

As a result of ongoing consolidation in the coal industry and our partnership with the Cline Group, we derive a greater percentage of our revenues from a smaller number of lessees.

In 2011, we derived 17.2% of our revenues from the Cline Group and 28.5% from Alpha Natural Resources. Cline’s Williamson mine alone was responsible for approximately 12.0% of our revenues in 2011. 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 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.

We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves, obtain other mineral reserves through acquisitions or effectively integrate new assets into our existing business.

Because our reserves decline as our lessees mine our minerals, our future success and growth depend, in part, upon our ability to acquire additional reserves that are economically recoverable. If we are unable to acquire additional mineral reserves on acceptable terms, our royalty revenues will decline as our reserves are depleted. Our ability to acquire additional mineral reserves is dependent in part on our ability to access the capital markets. In addition, if we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our royalty revenues may decline and we could experience a material adverse effect on our business, financial condition or results of operations.

If we acquire additional reserves, 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 not be able to obtain long-term financing on acceptable terms, which would limit our ability to make acquisitions.

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.

If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.

We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

 

   

the payment of minimum royalties;

 

   

marketing of the minerals mined;

 

   

mine plans, including the amount to be mined and the method of mining;

 

   

processing and blending minerals;

 

   

expansion plans and capital expenditures;

 

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credit risk of their customers;

 

   

permitting;

 

   

insurance and surety bonding;

 

   

acquisition of surface rights and other mineral estates;

 

   

employee wages;

 

   

transportation arrangements;

 

   

compliance with applicable laws, including environmental laws; and

 

   

mine closure and reclamation.

A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell minerals at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for small or isolated mineral reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of minerals mined 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.

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 growing infrastructure business exposes us to risks that we do not experience in the royalty business.

Over the past few years, we have acquired several preparation plants, load-out facilities and beltlines. These facilities are subject to mechanical and operational breakdowns that could halt or delay the transportation and processing of coal, and therefore decrease our revenues. In addition, we have assumed the capital and operating risks associated with the transportation infrastructure at the Williamson mine. Although we have sub-contracted out this work to a third party, we could experience increased costs as well as increased liability exposure associated with operating these facilities.

 

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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 variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:

 

   

future prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs;

 

   

future mining technology improvements;

 

   

the effects of regulation by governmental agencies; and

 

   

geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in areas where our lessees currently mine.

Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on our reserve data that is included in this report.

A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.

Risks Inherent in an Investment in Natural Resource Partners L.P.

Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.

Because distributions on the common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend 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.

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.

 

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Unitholders may not be able to remove our general partner even if they wish to do so.

Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding units (including units held by our general partner and its affiliates). Because the owners of our general partner, along with directors and executive officers and their affiliates, own a significant percentage of our outstanding common units, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates.

In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwise change our management:

 

   

generally, if a person acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and

 

   

our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of management.

As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

We may issue additional common units without unitholder approval, which would dilute a unitholder’s existing ownership interests.

Our general partner may cause us to issue an unlimited number of common units, without unitholder approval (subject to applicable New York Stock Exchange (NYSE) rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units without unitholder approval (subject to applicable NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

an existing unitholder’s proportionate ownership interest in NRP will decrease;

 

   

the amount of cash available for distribution on each unit may decrease;

 

   

the relative voting strength of each previously outstanding unit may be diminished; and

 

   

the market price of the common units may decline.

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.

Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same

 

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extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Conflicts of interest could arise among our general partner and us or the unitholders.

These conflicts may include the following:

 

   

we do not have any employees and we rely solely on employees of affiliates of the general partner;

 

   

under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;

 

   

the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly distributions to unitholders;

 

   

the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability;

 

   

under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arm’s-length negotiations; and

 

   

the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights to one of its affiliates or to us.

The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers with its own choices and to control their decisions and actions.

In addition, a change of control would constitute an event of default under our revolving credit agreement. During the continuance of an event of default under our revolving credit agreement, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us and/or declare all amounts payable by us immediately due and payable. A change of control also may trigger payment obligations under various compensation arrangements with our officers.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for 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 federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

 

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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for 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 pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a 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 the unitholders, likely causing a substantial reduction in the value of our common units.

In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, legislation was proposed in a prior session of Congress that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to us as proposed, it could be reintroduced or amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us by any state will reduce the cash available for distribution to you.

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 liability that results from 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 units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those 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

 

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addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your 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. Distributions to non-U.S. persons will be reduced by withholding taxes, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their shares 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 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.

To maintain the uniformity of the economic and tax characteristics of our common units, 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 units each month based upon the ownership of our 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 prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department 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. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to 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 units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

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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 our 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 fiscal 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 a 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 his taxable income for the year of termination. Our termination 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 tax purposes. 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 tax years 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 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 United States federal, state and local tax returns.

 

Item 1B. Unresolved Staff Comments

None.

 

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Item 2. Properties

Major Coal Properties

The following is a summary of our major coal producing properties in each region. For information regarding our Coal Reserves and Production as well as other information related to our coal properties, please see “Item 1. Business.”

Northern Appalachia

Beaver Creek.    The Beaver Creek property is located in Grant and Tucker Counties, West Virginia. In 2011, 2.4 million tons were produced from this property. We lease this property to Mettiki Coal, LLC, a subsidiary of Alliance Resource Partners L.P. Coal is produced from an underground longwall mine. 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 and to various export customers.

Allegany County, Maryland.    In 2011, 366,000 tons were produced from the property. We lease this property to Vindex Energy, a subsidiary of Arch Coal. Coal from this property is produced from a surface mine. The raw coal is trucked to the Warrior plant of Allegheny Energy.

Area F.    In 2011, 283,000 tons were produced from the property. We lease this property to Carter Roag, a subsidiary of Metinvest. Coal from this property is produced from an underground mine. The raw coal is trucked to a preparation plant operated by the lessee. Coal is shipped via rail to domestic metallurgical customers and exported for use by Metinvest.

 

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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 2011, 4.9 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.

Lynch.    The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2011, 4.8 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. Coal is transported by truck to a preparation plant on the property and is shipped primarily on the CSX railroad to utility customers such as Georgia Power and Orlando Utilities.

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 2011, 2.8 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 2011, 2.5 million tons were produced from this property. Coal is produced from a number of lessees 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 2011, 2.1 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 customers such as Georgia Power and the Tennessee Valley Authority.

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 2011, 2.0 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.

Pardee.    The Pardee property is located in Letcher County, Kentucky and Wise County, Virginia. In 2011, 1.8 million tons were produced from this property. We lease the property to a subsidiary of Arch Coal, Inc. Production comes from underground and surface mines and is transported by truck or beltline to a preparation plant on the property and shipped primarily on the Norfolk Southern railroad to utility customers such as Georgia Power and the Tennessee Valley Authority and domestic and export metallurgical customers such as Algoma Steel and Arcelor.

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 2011, 1.5 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. The map on the following page shows the location of our properties in Central Appalachia.

The map on the following page shows the location of our properties in Central Appalachia.

 

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Southern Appalachia

BLC Properties.    The BLC properties are located in Kentucky and Tennessee. In 2011, 1.2 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 Kopper-Glo Fuels. 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 Southern Company, South Carolina Electric & Gas, and numerous medium and small industrial customers.

Oak Grove.    The Oak Grove property is located in Jefferson County, Alabama. In 2011, 470,000 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. In late April 2011, the overland conveyor and preparation plant serving this mine were damaged by a tornado. Repairs continued through the year then the plant resumed operations in January 2012. For a portion of the second half of the year the mine resumed production and stockpiled raw coal to be processed upon completion of the repairs.

 

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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 the Cline Group, and in 2011, 6.8 million tons were mined on the property. This production is from a longwall mine. Production is shipped primarily via CN railroad to customers such as Duke and to various export customers.

Macoupin.    The Macoupin property is located in Macoupin County, Illinois. The property is under lease to an affiliate of the Cline Group, and in 2011, 1.8 million tons were shipped from the property. Production is from an underground mine and is shipped via the Norfolk Southern or Union Pacific railroads or by barge to customers such as Western KY Energy and other midwest utilities or loaded into barges for shipment to export customers.

Sato.    The Sato property is located in Jackson County, Illinois. In 2011, 363,000 tons were produced from the property. The property is under lease to Knight Hawk Coal LLC, which is principally owned by Arch Coal. Production is currently from a surface mine, and coal is shipped by truck and railroad to various midwest and southeast utilities.

The map below shows the location of our properties in 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 2011, 2.7 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 and by the Burlington Northern Santa Fe railroad to Minnesota Power. A small amount of coal is transported by truck to other customers.

The map below shows the location of our properties in Northern Powder River Basin.

 

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BRP Properties

In June 2010, we and International Paper formed BRP. As of December 31, 2011, BRP had acquired, in several stages from International Paper, approximately 8.8 million mineral acres in 29 states. While the vast majority of the 8.8 million acres remain largely undeveloped and underexplored, BRP currently holds 78 revenue generating leases including 18 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 72,000 acres are under 45 leases as of December 31, 2011. In addition, BRP holds a gross production royalty interest on approximately 23,000 mineral acres currently under lease in Louisiana. The remaining oil and gas mineral acreage in Louisiana is not leased but a significant number of acres are in areas with development potential.

As of December 31, 2011, BRP owned nearly 246,000 gross 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.

Other mineral rights held by BRP as of December 31, 2011 included coalbed methane rights in four Gulf Coast states, metal prospect rights in four states, approximately 450,000 acres of water and royalty rights in East Texas, geothermal rights and 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 on the following page illustrates the location of BRP’s current mineral rights.

 

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Title to Property

Of the approximately 2.3 billion tons of proven and probable coal reserves that we owned or controlled as of December 31, 2011, we owned approximately 99% of the reserves in fee. We lease approximately 20 million tons, or less than 1% of our reserves, from unaffiliated third parties. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operations of our business.

For most of our properties, the surface, oil and gas and mineral or coal estates are owned by different 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.

 

Item 3. Legal Proceedings

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, we believe these claims will not have a material effect on our financial position, liquidity or operations.

 

Item 4. Mine Safety Disclosures

Not applicable.

 

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PART II

 

Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units are listed and traded on the NYSE under the symbol “NRP”. As of February 14, 2012, there were approximately 45,700 beneficial and registered holders of our common units. The computation of the approximate number of unitholders is based upon a broker survey.

The following table sets forth the high and low sales prices per common unit, as reported on the NYSE Composite Transaction Tape from January 1, 2010 to December 31, 2011, and the quarterly cash distribution declared and paid with respect to each quarter per common unit.

 

     Price Range      Cash Distribution History  
     High      Low      Per
Unit
     Record
Date
     Payment
Date
 

2010

              

First Quarter

   $ 27.56       $ 21.46       $ 0.5400         05/05/2010         05/14/2010   

Second Quarter

   $ 26.01       $ 18.00       $ 0.5400         08/05/2010         08/13/2010   

Third Quarter

   $ 27.65       $ 22.85       $ 0.5400         11/05/2010         11/12/2010   

Fourth Quarter

   $ 33.38       $ 26.25       $ 0.5400         02/04/2011         02/14/2011   

2011

              

First Quarter

   $ 37.80       $ 32.24       $ 0.5400         05/05/2011         05/13/2011   

Second Quarter

   $ 35.44       $ 29.26       $ 0.5400         08/05/2011         08/12/2011   

Third Quarter

   $ 35.03       $ 23.98       $ 0.5500         11/04/2011         11/14/2011   

Fourth Quarter

   $ 30.48       $ 23.36       $ 0.5500         02/03/2012         02/14/2012   

On September 20, 2010, we eliminated all of the incentive distribution rights (IDRs) held by the general partner and affiliates of the general partner. As consideration for the elimination of the IDRs, we issued 32 million common units to the holders of the IDRs. Prior to the transaction, the IDRs received approximately 24% of the quarterly distributions and 48% of any increase in the distribution. Following the transaction, the general partner retained its 2% interest in NRP.

Cash Distributions to Partners

(In thousands)

 

     General
Partner
     Limited
Partners
     IDRs      Total
Distributions
 

2009

           

Distributions

   $ 3,762       $ 144,766       $ 39,607       $ 188,135   

2010

           

Distributions

   $ 4,197       $ 174,709       $ 30,943       $ 209,849   

2011

           

Distributions

   $ 4,696       $ 230,080       $       $ 234,776   

We must distribute all of our cash on hand at the end of each quarter, less cash reserves established by our general partner. We refer to this cash as “available cash” as that term is defined in our partnership agreement. The amount of available cash may be greater than or less than the minimum quarterly distribution. Provisions of our credit facility and note purchase agreement may restrict our ability to make distributions under certain limited circumstances. Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations- Contractual Obligations and Commercial Commitments.”

 

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Item 6. Selected Financial Data

The following table shows selected historical financial data for Natural Resource Partners L.P. for the periods and as of the dates indicated. We derived the information in the following tables from, and the information should be read together with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in Item 8, “Financial Statements and Supplementary Data” in this and previously filed Forms 10-K. These tables should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

NATURAL RESOURCE PARTNERS L.P.

(In thousands, except per unit and per ton data)

 

     For the Years Ended December 31,  
     2011      2010      2009      2008      2007  

Total revenues

   $ 377,683       $ 301,401       $ 256,084       $ 291,665       $ 214,985   

Asset impairments

   $ 161,336       $       $       $       $   

Income from operations

   $ 104,135       $ 196,061       $ 153,975       $ 197,007       $ 128,299   

Net income

   $ 54,026       $ 154,461       $ 114,080       $ 170,006       $ 102,499   

Basic and diluted net income per limited partner unit

   $ 0.50       $ 1.54       $ 1.17       $ 1.95       $ 1.11   

Distributions ($ per unit)

   $ 2.17       $ 2.16       $ 2.16       $ 2.07       $ 1.88   

Weighted average number of units outstanding

     106,028         81,917         67,702         64,891         64,505   

Cash from operations

   $ 305,574       $ 258,694       $ 210,669       $ 229,956       $ 168,153   

Balance sheet data:

              

Cash and cash equivalents

   $ 214,922       $ 95,506       $ 82,634       $ 89,928       $ 58,341   

Total assets

   $ 1,665,649       $ 1,664,036       $ 1,523,590       $ 1,301,340       $ 1,320,031   

Long-term debt

   $ 836,268       $ 661,070       $ 626,587       $ 478,822       $ 496,057   

Partners’ capital

   $ 644,915       $ 825,180       $ 765,226       $ 743,341       $ 744,591   

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing. For more detailed information regarding the basis of presentation for the following financial information, see the Notes to the Consolidated Financial Statements.

Executive Overview

Our Business

We engage principally in the business of owning, managing and leasing mineral properties in the United States. We own coal reserves in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. As of December 31, 2011, we owned or controlled approximately 2.3 billion tons of proven and probable coal reserves, and we also owned approximately 380 million tons of aggregate reserves in a number of states across the country. 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.

Our revenue and profitability are dependent on our lessees’ ability to mine and market our reserves. Most of our coal is produced by large companies, many of which are publicly traded, with experienced and professional sales departments. A significant portion of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. In contrast, our aggregate properties are typically mined by regional operators with significant experience and knowledge of the local markets. The aggregates are sold at current market prices, which historically have increased along with the producer price index for sand and gravel. Over the long term, both our coal and aggregate royalty revenues are affected by changes in the demand for and the market price of the commodities.

In our 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 vary 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.

In addition to coal and aggregate royalty revenues, we generated approximately 24% of our 2011 and 25% of our 2010 revenues from other sources. We also receive oil and gas revenues from our BRP venture with International Paper, and have made several oil and gas mineral acquisitions over the last 12 months. Other sources of revenue include: processing and transportation fees; overriding royalties; wheelage payments; rentals; property tax revenue; and timber sales.

Our Current Liquidity Position

In August 2011, we amended and restated our credit facility, extending the maturity to August 2016. As of December 31, 2011, we had the full $300 million in available capacity under our credit facility and approximately $215 million in cash. Following the end of the year, we used approximately $60 million of our cash to fund acquisitions, and have approximately $18 million in remaining proceeds from our 2011 senior notes offerings that are designated for specific future acquisitions, including the completion of the Hillsboro acquisition in August of 2012. We believe that the combination of our capacity under our credit facility and our cash on hand gives us enough liquidity to meet our current financial needs.

In addition, other than a $35 million senior note that matures in 2013, we have annual principal payments on all our long-term debt. Although these annual payments will increase significantly beginning in 2013, we have no need to access the capital markets to pay off or refinance any of our senior note obligations other than the one note. Our outstanding principal balance will be reduced on all our debt as our minerals are depleted.

 

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Current Results/Outlook for 2012

For the year ended December 31, 2011, our lessees produced 55.1 million tons of coal and aggregates, generating $286.0 million in royalty revenues from our properties, and our total revenues were $377.7 million. We benefitted in 2011 from our substantial exposure to metallurgical coal, from which we derived approximately 45% of our coal royalty revenues on 34% of total production. Although the market softened slightly in the fourth quarter of the year, the prices received by our lessees for metallurgical coal remained at high levels, resulting in significantly improved results, especially from our Central Appalachian properties.

Looking forward, the market for both metallurgical and steam coal has slowed significantly in the first quarter of 2012, with extremely low natural gas prices resulting in significant displacement of coal by gas for domestic power production. In addition, unseasonably warm weather has resulted in lower demand for coal. Further, the federal government regulations dealing with air quality at power plants will lead to the closure of a number of coal-fired power plants, which will certainly have an impact on demand in 2012. The concerns about the European economy have dampened demand for metallurgical coal, as has reduced international demand for steel. Due to the above factors, our lessees entered 2012 with a significant amount of metallurgical coal unpriced. Thus, we have a lot of uncertainty as 2012 begins.

Growth Through Acquisitions

We have continued to diversify our holdings by expanding our presence in the Illinois Basin and through additional aggregates and other mineral acquisitions, including oil and gas royalties. Our expansion into Illinois is primarily through the acquisition of reserves by us and the development of greenfield mines by Cline. These projects take several years to reach full production, and it is difficult for us to forecast the timing of completion of the projects. To protect against this risk, we are receiving significant minimum royalties with respect to each of the projects. Although minimums provide cash to us that can be distributed to our limited partners, the minimums are generally not revenue to us until recouped through production or at the end of the recoupment period. Thus, to the extent that the development takes longer than anticipated to begin production, it will impact the revenues that we receive in the future.

In addition to our growth in the Illinois Basin, we expect to see continued growth in 2012 in our aggregates royalties and our oil and gas royalties through both new acquisitions and previously acquired properties that will be emerging out of the development phase in 2012.

Issues at Gatling Mines in West Virginia and Ohio

Operations at the Gatling West Virginia mine were idled in April 2010 and had not been restarted as of the end of the third quarter 2011. In October 2011, Gatling LLC, the Cline affiliate that owns the mine, informed us that it was no longer projecting production from the mine for the foreseeable future and is considering selling the mine. NRP and Gatling amended the lease with respect to this property to provide that the minimum royalty balance of $24.1 million would be non-recoupable, that Gatling would pay $3.4 million in non-recoupable minimum royalties through the first quarter of 2012, that the minimums would be reduced to a nominal amount after the first quarter of 2012, and that Gatling will continue to maintain and ventilate the mine. This property did not produce any coal in 2011 and NRP’s 2012 guidance does not include any production or revenues for the property.

Based on the information above, we determined that our investment in the Gatling West Virginia property would not be fully recovered by future cash flows. The net book value of the assets relating to this operation was $127.6 million as of September 30, 2011, and as of the date of our third quarter Form 10-Q, we had received $24.1 million in unrecouped minimum royalties. Due to these circumstances, we recognized an impairment charge of $90.9 million during the third quarter of 2011 with respect to the Gatling West Virginia assets. We do not believe that the non-cash impairment will materially impact our future revenues or distributable cash flows.

In addition to the impairment of the assets associated with the Gatling West Virginia mine, another Cline affiliate, Gatling Ohio, LLC, has recently encountered adverse geologic conditions at its mine across the Ohio River in Meigs County, Ohio. This mine represents approximately 1% of our 2011 revenues. Historically, two continuous miner units have operated in the mine, but both of those two units have recently shut down due to the

 

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incursion of significant sandstone into the coal seam, and Gatling Ohio informed us in late December that it is uneconomical for it to continue to operate the mine, has idled the operation indefinitely and has declared force majeure on its coal sales contracts. The net book value of the assets relating to this operation was $93.4 million as of December 31, 2011, prior to the impairment charge. As of the date of this report, we have received $9.6 million in previously unrecouped minimum royalties.

Considering all available information at this time, we have determined that our investment in the Gatling Ohio property will not be fully recovered by future cash flows. As a result, we recognized an impairment charge of $70.4 million during the fourth quarter of 2011 with respect to the Gatling Ohio assets. This impairment charge and the related impairment charge on the Gatling West Virginia assets have materially impacted our earnings in the periods in which the impairments were recognized, but will not materially impact our cash flows from operations or our distributable cash flow.

Political, Legal and Regulatory Environment

The political, legal and regulatory environment continues to be difficult for the coal industry. The EPA has used its authority to create significant delays in the issuance of new permits and even revoke existing permits. The continued uncertainty regarding the permitting of coal mines in Appalachia has led to substantial delays and increased costs for coal operators.

In addition to the increased oversight of the EPA, MSHA has increased its involvement in the approval of plans and enforcement of safety issues in connection with mining. The 2010 mine disaster at Massey’s Upper Big Branch Mine has led to even more scrutiny by MSHA of our lessees’ operations, as well as additional mine safety legislation being considered by Congress. MSHA’s involvement has increased the cost of mining due to more frequent citations and much higher fines imposed on our lessees as well as the overall cost of regulatory compliance. Combined with the difficult economic environment and the higher costs of mining in general, MSHA’s recent increased participation in the mine development process could significantly delay the opening of new mines.

The EPA is also using the existing Clean Air Act to regulate GHGs. In April 2007, the U.S. Supreme Court rendered its decision in Massachusetts v. EPA, finding that the EPA has authority under the Clean Air Act to regulate carbon dioxide emissions from automobiles and can decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endanger public health or the environment. In response to Massachusetts v. EPA, the EPA published a final rule that requires the reporting of greenhouse gas emissions from all sectors of the American economy, although reporting of emissions from underground coal mines and coal suppliers as originally proposed has been deferred pending further review. In December 2009, the EPA determined that six GHGs, including carbon dioxide and methane, endanger the public health and welfare of current and future generations. In the same rulemaking, the EPA found that emission of GHGs from new motor vehicles and their engines contribute to greenhouse gas pollution. Although Massachusetts v. EPA did not involve the EPA’s authority to regulate GHG emissions from stationary sources, such as coal-fueled power plants, the decision is likely to impact regulation of stationary sources. Several petitioners have challenged the EPA’s findings in the Washington D.C. Circuit Court of Appeals, and that litigation is ongoing.

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 less actual principal payments and cash reserves set aside for future scheduled principal payments on our senior notes. Although distributable cash flow is a “non-GAAP financial measure,” we believe it is a useful adjunct to net cash provided by operating activities

 

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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 NRP as for other companies. A reconciliation of distributable cash flow to net cash provided by operating activities is set forth below.

Reconciliation of GAAP “Net cash provided by operating activities”

to Non-GAAP “Distributable cash flow”

 

     For the Years Ended December 31,  
     2011     2010     2009  

Net cash provided by operating activities

   $ 305,574      $ 258,694      $ 210,669   

Less scheduled principal payments

     (31,518     (32,234     (17,235

Less reserves for future principal payments

     (31,159     (31,699     (32,235

Add reserves used for scheduled principal payments

     31,518        32,234        17,235   
  

 

 

   

 

 

   

 

 

 

Distributable cash flow

   $ 274,415      $ 226,995      $ 178,434   
  

 

 

   

 

 

   

 

 

 

Recent Acquisitions

We are a growth-oriented company and have closed a number of acquisitions over the last several years. Our most recent acquisitions are briefly described below.

Colt.    Between September 2009 and February 2012, we had acquired approximately 118.1 million tons of an estimated total of 200 million tons of reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the Cline Group, for approximately $215 million of the $255 million purchase price. The final closing is anticipated to occur in the third quarter of 2012.

Oklahoma Oil and Gas.    From December 2011 through February 2012, we acquired approximately 9,500 net mineral acres located in the Mississippian Lime oil play in Northern Oklahoma for $32.6 million.

Royal.    In July 2011, we acquired approximately 44,000 acres of coal reserves and coal bed methane located in Pennsylvania and Illinois from Royal Oil and Gas Corporation for $8.0 million.

NBR Sand.    In June 2011, we acquired an overriding royalty interest in approximately 711 acres of frac sand reserves near Tyler, Texas for $16.5 million.

East Tennessee Materials.    In March 2011, we acquired approximately 500 acres of mineral and surface rights related to limestone reserves in Cleveland, Tennessee near Chattanooga for $4.7 million.

CALX Resources.    In February 2011, we acquired approximately 500 acres of mineral and surface rights related to limestone reserves on the Tennessee River near Paducah, Kentucky for $16.0 million, of which $15.5 million was paid as of the date of this filing and the remaining $0.5 million will be paid as certain milestones are completed.

BRP LLC.    In June 2010, we and International Paper Company formed a venture, BRP LLC, to own and manage mineral assets previously owned by International Paper. Some of these assets are currently subject to leases, and certain other assets have not yet been developed but are available for future development by the venture. In exchange for a $42.5 million contribution we became the managing and controlling member with the right to designate two of the three managers of BRP. Identified tangible assets in the transaction include oil and gas, coal and aggregate reserves, as well the rights to coal bed methane, geothermal, CO2 sequestration, water rights, precious metals, industrial minerals and base metals. Certain properties, including oil and gas, coal and aggregates, as well as land leased for cell towers, are currently under lease and generating revenues.

Rockmart Slate.    In June 2010, we acquired approximately 100 acres of mineral and surface rights related to slate reserves in Rockmart, Georgia from a local operator for a purchase price of $6.7 million.

 

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Sierra Silica.    In April 2010, we acquired the rights to silica reserves on a 1,000 acre property in Northern California from Sierra Silica Resources LLC for $17.0 million.

North American Limestone.    In April 2010, we signed an agreement to build and own for the construction of a fine grind processing facility for high calcium carbonate limestone located in Putnam County, Indiana. We lease the facility to a local operator. The total cost of the facility was $6.5 million.

Northgate-Thayer.    In March 2010, we acquired approximately 100 acres of mineral and surface rights related to dolomite limestone reserves in White County, Indiana from a local operator for a purchase price of $7.5 million.

Massey-Override.    In March 2010, we acquired from Massey Energy (now Alpha Natural Resources) subsidiaries overriding royalty interests in coal reserves located in southern West Virginia and eastern Kentucky. Total consideration for this purchase was $3.0 million.

Critical Accounting Policies

Coal and Aggregate Royalties.    Coal and aggregate royalty revenues are recognized on the basis of tons of mineral sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell, subject to minimum annual or quarterly payments.

Processing and Transportation Fees.    Processing fees are recognized on the basis of tons of coal processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal that is processed and sold from the facilities. The processing leases are structured so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Coal transportation fees are recognized on the basis of tons of coal transported over the beltlines. Under the terms of the transportation contracts, we receive a fixed price per ton for all coal transported on the beltlines.

Oil and Gas Royalties.    Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some are subject to minimum annual payments or delay rentals.

Minimum Royalties.    Most of our lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

Depreciation, Depletion and Amortization.    We depreciate our plant and equipment on a straight line basis over the estimated useful life of the asset. We deplete mineral properties on a units-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage in those properties. We amortize intangible assets on a units-of-production basis, unless classified as a temporarily idled asset then a minimum amortization is applied. We estimate proven and probable mineral reserves with the assistance of third-party mining consultants, and we use estimation techniques and recoverability assumptions. We update our estimates of mineral reserves periodically and this may result in material adjustments to mineral reserves and depletion rates that we recognize prospectively. Historical revisions have not been material.

Asset Impairment.    If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.

Share-Based Payments.    We account for awards under our Long-Term Incentive Plan under Financial Accounting Standards Board’s (FASB) stock compensation authoritative guidance. This authoritative guidance

 

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provides that grants must be accounted for using the fair value method, which requires us to estimate the fair value of the grant and charge or credit the estimated fair value to expense over the service or vesting period of the grant based on fluctuations in value. In addition, this authoritative guidance requires that estimated forfeitures be included in the periodic computation of the fair value of the liability and that the fair value be recalculated at each reporting date over the service or vesting period of the grant.

Recent Accounting Pronouncements

In June 2011, the FASB amended the presentation of comprehensive income. The amendments in this update give us the option to present the total comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. These amendments are effective for fiscal years and interim periods within those years, beginning on or after December 15, 2011. We have not determined which method of presentation we will elect.

In May 2011, the FASB amended fair value measurement and disclosure requirements. The amendments result in common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs). Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principal or requirement for measuring fair value or for disclosing information about fair value measurements. The amendment likely to have the most impact on us relates to the fair value disclosure of the senior notes’ quantitative information about unobservable inputs used in fair value measurements, that is categorized within Level 3 of the fair value hierarchy. These amendments are effective for fiscal years and interim periods within those years, beginning on or after December 15, 2011. We do not expect this adoption to have a material impact on our financial position, results of operations or cash flows.

Other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies are not expected to have a material impact on our financial position, results of operations and cash flows.

 

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Results of Operations

Summary of 2011 and 2010 Royalties and Production

(In thousands, except percent and per ton data)

 

     For the Years Ended
December 31,
     Increase
(Decrease)
     Percentage
Change
 
     2011      2010        

Coal royalties

           

Appalachia

           

Northern

   $ 20,578       $ 18,676       $ 1,902         10%   

Central

     196,789         144,934         51,855         36%   

Southern

     11,717         19,405         (7,688)         (40)%   
  

 

 

    

 

 

    

 

 

    

Total Appalachia

     229,084         183,015         46,069         25%   

Illinois Basin

     41,324         30,210         11,114         37%   

Northern Powder River Basin

     7,658         8,444         (786)         (9)%   

Gulf Coast

     1,155         92         1,063         NMF*   
  

 

 

    

 

 

    

 

 

    

Total

   $ 279,221       $ 221,761       $ 57,460         26%   
  

 

 

    

 

 

    

 

 

    

Production (tons)

           

Appalachia

           

Northern

     5,251         4,900         351         7%   

Central

     29,555         27,056         2,499         9%   

Southern

     1,695         2,824         (1,129)         (40)%   
  

 

 

    

 

 

    

 

 

    

Total Appalachia

     36,501         34,780         1,721         5%   

Illinois Basin

     9,445         7,753         1,692         22%   

Northern Powder River Basin

     2,682         4,467         (1,785)         (40)%   

Gulf Coast

     523         52         471         NMF*   
  

 

 

    

 

 

    

 

 

    

Total

     49,151         47,052         2,099         4%   
  

 

 

    

 

 

    

 

 

    

Average gross royalty revenue per ton

           

Appalachia

           

Northern

   $ 3.92       $ 3.81       $ 0.11         3%   

Central

     6.66         5.36         1.30         24%   

Southern

     6.91         6.87         0.04         1%   

Total Appalachia

     6.28         5.26         1.02         19%   

Illinois Basin

     4.38         3.90         0.48         12%   

Northern Powder River Basin

     2.86         1.89         0.97         51%   

Gulf Coast

     2.28         1.77         0.51         29%   

Combined average gross royalty revenue per ton

   $ 5.68       $ 4.71       $ 0.97         21%   

Aggregates

           

Royalty revenues

   $ 6,640       $ 4,869       $ 1,771         36%   

Aggregate Bonus Royalty

   $ 94       $ (639)       $ 733         NMF*   

Production

     5,930         4,365         1,565         36%   

Average gross royalty revenue per ton

   $ 1.12       $ 1.12       $         NMF*   

Oil and Gas

           

Royalty

   $ 14,017       $ 7,720       $ 6,297         82%   

 

 

* (NMF) Not meaningful.

 

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Coal Royalty Revenues and Production

Coal royalty revenues comprised approximately 74% of our total revenue for both years ended December 31, 2011 and 2010, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

Appalachia.    Primarily as a result of higher prices being received by our lessees in Northern and Central Appalachia, coal royalty revenues increased by $46.1 million in 2011. The 1.7 million ton increase in production was the result of several of our lessees in Northern and Central Appalachia having a greater proportion of production on our properties or mines moving onto our property. We also benefitted from much higher prices for the significant metallurgical coal production from our Central Appalachia properties. Additionally, repairs were completed at a preparation plant that was damaged by fire in 2010, allowing those mines to produce for the entire year. These increases more than offset the reduction in production in Southern Appalachia caused by a lessee having its preparation plant damaged by a tornado in late April.

Illinois Basin.    Coal royalty revenues and production on our properties were both higher in 2011. Coal royalty revenues increased by $11.1 million and production increased by 1.7 million tons. The increased production was due to production from our Williamson and Macoupin properties. The combination of having a greater proportion of our production from properties with higher royalty rates and our lessees receiving higher prices increased our royalty per ton.

Northern Powder River Basin.    The decrease in both coal royalty revenues of $0.8 million and production of 1.8 million tons on our Western Energy property was due to the normal variations that occur due to the checkerboard nature of our ownership. The higher prices received by our lessee and the resultant higher revenue per ton did help to partially offset some of the lower production.

Aggregates Royalty Revenues and Production

For the year ended December 31, 2011, we recognized $6.7 million in royalty revenue from aggregates, which included a bonus payment of $0.1 million under the terms of one of our leases. For the same period for 2010, we recognized royalty revenue from aggregates of $4.2 million, which included bonus revenue reversal of $0.6 million under the same lease. We had production of 5.9 million tons and 4.4 million tons for each of these years. Although production declined at our largest property in Dupont, Washington, the total production from our properties increased due to our recent acquisitions of additional reserves.

Oil and Gas Royalty Revenues

Oil and gas royalty revenues increased 82% to $14.0 million due to a full year of ownership of the BRP properties. Oil and gas royalty revenues include production revenues as well as bonus payments.

 

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Summary of 2010 and 2009 Royalties and Production

(In thousands, except percent and per ton data)

 

     For the Years Ended
December 31,
     Increase
(Decrease)
    Percentage
Change
 
     2010     2009       

Coal royalties

         

Appalachia

         

Northern

   $ 18,676      $ 14,959       $ 3,717        25

Central

     144,934        132,543         12,391        9

Southern

     19,405        19,382         23        <1
  

 

 

   

 

 

    

 

 

   

Total Appalachia

     183,015        166,884         16,131        10

Illinois Basin

     30,210        22,019         8,191        37

Northern Powder River Basin

     8,444        7,718         726        9

Gulf Coast

     92                92        100
  

 

 

   

 

 

    

 

 

   

Total

   $ 221,761      $ 196,621       $ 25,140        13
  

 

 

   

 

 

    

 

 

   

Production (tons)

         

Appalachia

         

Northern

     4,900        4,943         (43     (1 )% 

Central

     27,056        28,032         (976     (3 )% 

Southern

     2,824        3,233         (409     (13 )% 
  

 

 

   

 

 

    

 

 

   

Total Appalachia

     34,780        36,208         (1,428     (4 )% 

Illinois Basin

     7,753        6,656         1,097        16

Northern Powder River Basin

     4,467        3,984         483        12

Gulf Coast

     52                52        100
  

 

 

   

 

 

    

 

 

   

Total

     47,052        46,848         204        <1
  

 

 

   

 

 

    

 

 

   

Average gross royalty revenue per ton

         

Appalachia

         

Northern

   $ 3.81      $ 3.03       $ 0.78        26

Central

     5.36        4.73         0.63        13

Southern

     6.87        6.00         0.87        15

Total Appalachia

     5.26        4.61         0.65        14

Illinois Basin

     3.90        3.31         0.59        18

Northern Powder River Basin

     1.89        1.94         (0.05     (3 )% 

Gulf Coast

     1.77                1.77        100

Combined average gross royalty revenue per ton

   $ 4.71      $ 4.20       $ 0.51        12

Aggregates

         

Royalty revenues

   $ 4,869      $ 4,260       $ 609        14

Aggregate Bonus Royalty

   $ (639   $ 1,320       $ (1,959     (148 )% 

Production

     4,365        3,269         1,096        34

Average gross royalty revenue per ton

   $ 1.12      $ 1.30       $ (0.18     (14 )% 

Oil and Gas

         

Royalty

   $ 7,720      $ 7,520       $ 200        3

 

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Coal Royalty Revenues and Production

Coal royalty revenues comprised approximately 74% and 77% of our total revenue for the years ended December 31, 2010 and 2009, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

Appalachia.    Primarily as a result of higher prices being received by our lessees, and the improved royalty rates negotiated on one of our leases, coal royalty revenues increased by $16.1 million in 2010. The 1.4 million ton decline in production was the result of some reductions in production in response to the coal markets, a fire at one of the preparation plants on our property, the temporary idling of two mines and some mines moving their production onto adjacent property.

Illinois Basin.    Coal royalty revenues and production on our properties were both higher in 2010. Coal royalty revenues increased by $8.2 million and production increased by 1.1 million tons. The increased production was due to the mine on our Macoupin property operating for the entire year and some of the other mines having increased production. In general, our lessees received higher prices for their production, increasing our royalty per ton.

Northern Powder River Basin.    The increase in both coal royalty revenues of $0.7 million and production of 483,000 tons on our Western Energy property was due to the normal variations that occur due to the checkerboard nature of our ownership.

Aggregates Royalty Revenues and Production

We own aggregate reserves in a number of states across the country. For the year ended December 31, 2010, we recognized $4.2 million in royalty revenue from aggregates, which included a reversal of a bonus payment accrual of $0.6 million, under the terms of one of our leases. For the same period for 2009, we recognized royalty revenue from aggregates of $5.6 million, which included bonus revenue of $1.3 million under the same lease. We had production of 4.4 million tons and 3.3 million tons for each of these years.

Other Operating Results

Processing and Transportation Revenues.    We generated $13.5 million, $9.6 million and $7.7 million in processing revenues for the years ended December 31, 2011, 2010 and 2009, respectively. We do not operate the preparation plants, but receive a fee for material processed through them. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the material that is processed through the facilities. The increase in processing revenues for the year ended December 31, 2011 and 2010 is primarily due to higher volumes at higher prices. The increase in 2010 also reflects the addition of the preparation plant at Macoupin being online for a full year.

In addition to our preparation plants, we own coal handling and transportation infrastructure in West Virginia, Ohio and Illinois. In contrast to our typical royalty structure, we receive a fixed rate per ton for coal transported over these facilities. For the assets other than our loadout facility at the Shay No. 1 mine in Illinois, we operate coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We generated transportation fees from these assets of approximately $16.7 million, $14.6 million and $12.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. The steady increase in transportation fees from 2009 to 2011 is due to increased volumes from our lessee operations in the Illinois Basin.

Additional Revenues.    In addition to coal royalties, aggregate royalties, processing and transportation revenues, we generated approximately 16%, 17% and 13% of our revenues from other sources for the years ended December 31, 2011, 2010 and 2009, respectively. These other sources include: oil and gas royalties, property taxes, minimums recognized, overriding royalties, timber, rentals, wheelage and other income. Minimums recognized as revenues increased in 2010 by $12.9 million primarily due to a non-recoupable minimum on our Colt reserves received in 2010. In future years, the minimums received with respect to this property will be reflected as revenue only when recouped through production.

 

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Operating costs and expenses.    Included in total expenses are:

 

   

Depreciation, depletion and amortization were $65.1 million, $57.0 million and $60.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. Excluding a one-time expense of $8.2 million for a terminated lease due to a mine closure, depletion increased from 2009 due to a refinement of our accounting policy for contract amortization during 2010. Other than the one-time adjustment, depreciation, depletion and amortization was approximately the same for all three years.

 

   

General and administrative expenses were $29.6 million, $29.9 million and $23.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. The change in general and administrative expense is primarily due to accruals under our long-term incentive plan attributable to fluctuations in our unit price and additional personnel required to manage our properties. The increase from 2010 over 2009 also reflects expenses of $2.5 million associated with the formation of the venture with International Paper Company during 2010.

 

   

Property, franchise and other taxes were $14.5 million, $15.1 million and $15.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. A substantial portion of our property taxes is reimbursed to us by our lessees and is reflected as property tax revenue on our statements of income.

Interest Expense.    Interest expense was $49.1 million, $41.6 million and $40.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. Due to additional debt incurred in 2011 to fund acquisitions, interest expense has increased since 2010.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

We satisfy our working capital requirements with cash generated from operations. Since our initial public offering, we have financed our property acquisitions with available cash, borrowings under our revolving credit facility, and the issuance of our senior notes and additional units. While our ability to satisfy our debt service obligations and pay distributions to our unitholders depends in large part on our future operating performance, our ability to make acquisitions will depend on prevailing economic conditions in the financial markets as well as the coal, oil and gas and aggregate industries and other factors, some of which are beyond our control. For a more complete discussion of factors that will affect cash flow we generate from operations, please read “Item 1A. Risk Factors.” Our capital expenditures, other than for acquisitions, have historically been minimal.

In August 2011, we amended and extended our credit facility until August 2016. Our debt covenant ratios are in compliance for both our credit facility and our outstanding senior notes. In addition, we are amortizing substantially all of our senior notes and have no immediate need to refinance. For a more complete discussion of factors that will affect our liquidity, please read “Item 1A. Risk Factors.” During 2011, we continued to review our banking relationships and our internal policies regarding deposit concentrations with specific attention to effectively managing risk in the current banking environment. We had approximately $214.9 million of cash available at the end of the year.

Net cash provided by operations for the years ended December 31, 2011, 2010 and 2009 was $305.6 million, $258.7 million and $210.7 million, respectively. The most significant portion of our cash provided by operations is generated from coal royalty revenues.

Net cash used in investing activities for the years December 31, 2011, 2010 and 2009 was $115.1 million, $170.8 million and $119.9 million, respectively. In each of those years, substantially all of our investing activities consisted of acquiring coal reserves, plant and equipment and other mineral rights.

Net cash used for financing activities for the years ended December 31, 2011, 2010 and 2009 was $71.1 million, $75.0 million and $98.1 million, respectively. We had proceeds from loans of $385.0 million, $140.0 million and $331.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. We had proceeds from the issuance of units of $110.4 million for the year ended December 31, 2010. We did not issue any units for the years ended December 31, 2011 and 2009. We used a portion of the proceeds from the equity

 

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and debt issuance to repay the credit facility borrowings of $179.0 million, $74.0 million and $151.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. We also made $31.5 million, $32.2 million, and $17.2 million in principal payments on our senior notes for the years ended December 31, 2011, 2010 and 2009, respectively. We also retired purchase obligations related to the purchase of reserves and infrastructure of $7.6 million, $9.2 million and $72.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. We paid distributions of $234.8 million, $209.8 million and $188.1 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Contractual Obligations and Commercial Commitments

Credit Facility.    We amended and restated our $300 million revolving credit facility in August 2011, and as of the date of this report we had the full amount available to us under the facility. Under an accordion feature in the credit facility, we may request our lenders to increase their aggregate commitment to a maximum of $500 million on the same terms. However, we cannot be certain that our lenders will elect to participate in the accordion feature. To the extent the lenders decline to participate, we may elect to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be available to us on existing or comparable terms.

During 2011, our borrowings and repayments under our credit facility were as follows:

 

     Quarters Ending  
     March 31,
2011
     June 30,
2011
     September 30,
2011
     December 31,
2011
 
     (In thousands)  

Outstanding balance, beginning of period

   $ 94,000       $ 179,000       $         —       $         —   

Borrowings under credit facility

     85,000                           

Less: Repayments under credit facility

             179,000                   
  

 

 

    

 

 

    

 

 

    

 

 

 

Outstanding balance, ending period

   $ 179,000       $       $       $   
  

 

 

    

 

 

    

 

 

    

 

 

 

Our obligations under the credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under the revolving credit facility bears interest, at our option, at either:

 

   

the Alternate Base Rate (as defined in the credit agreement) plus an applicable margin ranging from 0% to 1%; or

 

   

the Adjusted LIBO Rate (as defined in the credit agreement) plus an applicable margin ranging from 1.00% to 2.25%.

We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.18% to 0.40% per annum.

The credit agreement contains covenants requiring us to maintain:

 

   

a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0; and

 

   

a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) not less than 3.5 to 1.0.

Senior Notes.    NRP Operating LLC issued the senior notes listed below under a note purchase agreement as supplemented from time to time. The senior notes are unsecured but are guaranteed by our operating subsidiaries. We may prepay the senior notes at any time together with a make-whole amount (as defined in the note purchase agreement). If any event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies.

The senior note purchase agreement contains covenants requiring our operating subsidiary to:

 

   

maintain a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters;

 

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not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and

 

   

maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

During 2011, we issued $300 million of additional senior unsecured notes, which include $75.0 million of 4.73% notes due December 1, 2023, $175.0 million of 5.03% notes due December 1, 2026 and $50.0 million of 5.18% notes dues December 1, 2026. Proceeds from the senior notes were used to repay all of the outstanding balance under the revolving credit facility, and we used, or will use, the remaining proceeds for acquisitions. All tranches have semi-annual interest payments beginning December 1, 2011, and equal annual principal payments beginning December 1, 2014.

Long-Term Debt

At December 31, 2011, our debt consisted of:

 

   

$35.0 million of 5.55% senior notes due 2013;

 

   

$32.3 million of 4.91% senior notes due 2018;

 

   

$150.0 million of 8.38% senior notes due 2019;

 

   

$69.2 million of 5.05% senior notes due 2020;

 

   

$1.9 million of 5.31% utility local improvement obligation due 2021;

 

   

$33.6 million of 5.55% senior notes due 2023;

 

   

$75.0 million of 4.73% senior notes due 2023;

 

   

$195.0 million of 5.82% senior notes due 2024;

 

   

$50.0 million of 8.92% senior notes due 2024;

 

   

$175.0 million of 5.03% senior notes due 2026; and

 

   

$50.0 million of 5.18% senior notes due 2026.

Other than the 5.55% senior notes due 2013, which have only semi-annual interest payments, all of our senior notes require annual principal payments in addition to semi-annual interest payments. The scheduled principal payments on the 8.38% senior notes due 2019 do not begin until March 2013, the scheduled principal payments on the 8.92% senior notes due 2024 do not begin until March 2014, and the scheduled principal payments on the 4.73%, 5.03% and 5.18% senior notes do not begin until December 2014. We also make annual principal and interest payments on the utility local improvement obligation.

The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2011 (in millions):

 

     Payments Due by Period  

Contractual Obligations

   Total      2012      2013      2014      2015      2016      Thereafter  

Long-term debt principal payments (including current maturities)(1)

   $ 867.1       $ 30.8       $ 87.2       $ 81.0       $ 81.0       $ 81.0       $ 506.1   

Long-term debt interest payments(1)

     330.3         51.7         48.1         43.5         38.4         33.3         115.3   

Pending acquisitions(2)

     80.0         80.0                                           

Rental leases(3)

     4.2         0.6         0.5         0.5         0.5         0.5         1.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 1,281.6       $ 163.1       $ 135.8       $ 125.0       $ 119.9       $ 114.8       $ 623.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

 

(1) The amounts indicated in the table include principal or interest, as applicable, due on our senior notes, as well as the utility local improvement obligation related to our property in DuPont, Washington.

 

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(2) The amounts indicated in the table include $80.0 million related to the future anticipated acquisitions of coal reserves with Colt LLC. Future acquisitions from Colt LLC are based upon certain milestones relating to the new mines construction. Upon each closing we receive title to additional reserves. In January 2012, we completed one acquisition of coal reserves from Colt LLC for approximately $40.0 million.

 

(3) On January 1, 2009, we entered into a ten-year lease agreement for the rental of office space from Western Pocahontas Properties Limited Partnership. The rental obligations from this lease are included in the table above.

Shelf Registration Statement

In addition to our credit facility, on February 27, 2009 we filed an automatically effective shelf registration statement on Form S-3 with the SEC that is available for registered offerings of common units and debt securities. The amounts, prices and timing of the issuance and sale of any equity or debt securities will depend on market conditions, our capital requirements and compliance with our credit facility and senior notes.

Off-Balance Sheet Transactions

We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the years ended December 31, 2011, 2010 and 2009.

Environmental

The operations our lessees conduct on our properties are subject to federal and state environmental laws and regulations. Please see Item 1, “Business — Regulation and Environmental Matters.” As an owner of surface interests in some properties, we may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of our coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify us against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because we have no employees, employees of Western Pocahontas Properties Limited Partnership make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. We believe that our lessees will be able to comply with existing regulations and do not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on our financial condition or results of operations. We have neither incurred, nor are aware of, any material environmental charges imposed on us related to our properties for the period ended December 31, 2011. We are not associated with any environmental contamination that may require remediation costs. However, our lessees do conduct reclamation work on the properties under lease to them. Because we are not the permittee of the mines being reclaimed, we are not responsible for the costs associated with these reclamation operations. In addition, West Virginia has established a fund to satisfy any shortfall in reclamation obligations.

Related Party Transactions

Partnership Agreement

Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, we reimburse our general partner and its affiliates for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates.

 

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The reimbursements to our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as follows:

 

     For the Years Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Reimbursement for services

   $ 9,136       $ 7,358       $ 6,822   
  

 

 

    

 

 

    

 

 

 

For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement.”

Transactions with Cline Affiliates

Various companies controlled by Chris Cline lease coal reserves from NRP, and we provide coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in our general partner, as well as 16,686,672 common units. At December 31, 2011, we had accounts receivable totaling $8.44 million from Cline affiliates. Revenues from the Cline affiliates are as follows:

 

     For The Year Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Coal royalty revenues

   $ 42,474       $ 32,407       $ 23,325   

Processing fees

     2,975         1,337         193   

Transportation fees

     16,689         14,324         11,495   

Minimums recognized as revenue

             12,400           

Override revenue

     2,691         1,904         2,356   
  

 

 

    

 

 

    

 

 

 
   $ 64,829       $ 62,372       $ 37,369   
  

 

 

    

 

 

    

 

 

 

As of December 31, 2011, we had received $47.2 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $20.2 million was received in the current year.

We recognized an asset impairment of $90.9 million during the third quarter of 2011 related to certain of our assets at the Gatling WV location and $70.4 million during the fourth quarter of 2011 related to the Gatling Ohio location. These assets were acquired from and are leased by Cline affiliates.

We recognized a $3.0 million non-cash gain on a reserve exchange of over one million tons in Illinois with Williamson Energy. The tons received will be fully mined during 2012, while the tons exchanged are not included in the current mine plans.

Quintana Capital Group GP, Ltd.

Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in NRP’s conflicts policy.

A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. NRP currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. NRP owns and leases the plants to Taggart Global, which designs, builds and operates the plants. The lease payments are based on the sales price for the

 

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coal that is processed through the facilities. To date, we have acquired four facilities under this agreement with Taggart with a total cost of $46.6 million. Revenues from Taggart are as follows:

 

     For the Years Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Processing revenue

   $ 9,755       $ 5,874       $ 3,872   
  

 

 

    

 

 

    

 

 

 

At December 31, 2011, we had accounts receivable totaling $1.3 million from Taggart.

A fund controlled by Quintana Capital owns Kopper-Glo, a small coal mining company that is one of the Partnership’s lessees with operations in Tennessee. Revenues from Kopper-Glo are as follows:

 

     For the Years Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Coal royalty revenues

   $ 1,629       $ 1,545       $ 1,560   
  

 

 

    

 

 

    

 

 

 

NRP also had accounts receivable totaling $0.1 million from Kopper-Glo at December 31, 2011.

Office Building in Huntington, West Virginia

We lease substantially all of two floors of an office building in Huntington, West Virginia from Western Pocahontas at market rates. The terms of the lease were approved by our Conflicts Committee. We pay $0.5 million each year in lease payments.

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk, which includes adverse changes in commodity prices and interest rates.

Commodity Price Risk

We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. We estimate that over 65% of our coal is currently sold by our lessees under coal supply contracts that have terms of one year or more. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees’ failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees’ operations and adversely affect our coal royalty revenues. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices.

Interest Rate Risk

Our exposure to changes in interest rates results from borrowings under our credit facility, which are subject to variable interest rates based upon LIBOR or the federal funds rate plus an applicable margin. Management monitors interest rates and may enter into interest rate instruments to protect against increased borrowing costs. At December 31, 2011, we did not have any variable interest rate debt.

 

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Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

 

     Page  

Report of independent registered public accounting firm

     53   

Consolidated balance sheets as of December 31, 2011 and 2010

     54   

Consolidated statements of income for the years ended December 31, 2011, 2010, and 2009

     55   

Consolidated statements of partners’ capital for the years ended December 31, 2011, 2010 and 2009

     56   

Consolidated statements of cash flows for the years ended December 31, 2011, 2010 and 2009

     57   

Notes to consolidated financial statements

     58   

 

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners of Natural Resource Partners L.P.

We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2011 and 2010, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP

Houston, Texas

February 29, 2012

 

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit information)

 

     December 31,
2011
    December 31,
2010
 
ASSETS   

Current assets:

    

Cash and cash equivalents

   $ 214,922      $ 95,506   

Accounts receivable, net of allowance for doubtful accounts

     30,923        26,195   

Accounts receivable — affiliates

     10,138        7,915   

Other

     832        910   
  

 

 

   

 

 

 

Total current assets

     256,815        130,526   

Land

     24,534        24,543   

Plant and equipment, net

     46,185        62,348   

Coal and other mineral rights, net

     1,257,501        1,281,636   

Intangible assets, net

     75,164        161,931   

Loan financing costs, net

     4,846        2,436   

Other assets

     604        616   
  

 

 

   

 

 

 

Total assets

   $ 1,665,649      $ 1,664,036   
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL   

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 2,366      $ 1,388   

Accounts payable — affiliates

     375        499   

Obligation related to acquisition

     500          

Current portion of long-term debt

     30,801        31,518   

Accrued incentive plan expenses — current portion

     8,374        6,788   

Property, franchise and other taxes payable

     6,316        6,926   

Accrued interest

     10,761        9,811   
  

 

 

   

 

 

 

Total current liabilities

     59,493        56,930   

Deferred revenue

     113,303        109,509   

Accrued incentive plan expenses

     11,670        11,347   

Long-term debt

     836,268        661,070   

Partners’ capital:

    

Common units outstanding: (106,027,836)

     629,253        806,529   

General partner’s interest

     10,517        14,132   

Non-controlling interest

     5,638        5,065   

Accumulated other comprehensive loss

     (493     (546
  

 

 

   

 

 

 

Total partners’ capital

     644,915        825,180   
  

 

 

   

 

 

 

Total liabilities and partners’ capital

   $ 1,665,649      $ 1,664,036   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit data)

 

     For the Years Ended December 31,  
     2011     2010     2009  

Revenues:

      

Coal royalties

   $ 279,221      $ 221,761      $ 196,621   

Aggregate royalties

     6,734        4,230        5,580   

Processing fees

     13,475        9,604        7,673   

Transportation fees

     16,688        14,564        12,517   

Oil and gas royalties

     14,017        7,720        7,520   

Property taxes

     12,640        11,270        11,636   

Minimums recognized as revenue

     9,148        14,199        1,266   

Override royalties

     14,523        11,258        9,251   

Other

     11,237        6,795        4,020   
  

 

 

   

 

 

   

 

 

 

Total revenues

     377,683        301,401        256,084   

Operating costs and expenses:

      

Depreciation, depletion and amortization

     65,118        56,978        60,012   

Asset impairments

     161,336                 

General and administrative

     29,553        29,893        23,102   

Property, franchise and other taxes

     14,486        15,107        14,996   

Transportation costs

     2,033        1,864        1,611   

Coal royalty and override payments

     1,022        1,498        2,388   
  

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     273,548        105,340        102,109   
  

 

 

   

 

 

   

 

 

 

Income from operations

     104,135        196,061        153,975   

Other income (expense)

      

Interest expense

     (49,180     (41,635     (40,108

Interest income

     69        35        213   
  

 

 

   

 

 

   

 

 

 

Income before non-controlling interest

     55,024        154,461        114,080   

Non-controlling interest

     (998              
  

 

 

   

 

 

   

 

 

 

Net income

   $ 54,026      $ 154,461      $ 114,080   
  

 

 

   

 

 

   

 

 

 

Net income attributable to:

      

General partner

   $ 1,081      $ 2,570      $ 1,611   
  

 

 

   

 

 

   

 

 

 

Holders of incentive distribution rights

   $      $ 25,966      $ 33,515   
  

 

 

   

 

 

   

 

 

 

Limited partners

   $ 52,945      $ 125,925      $ 78,954   
  

 

 

   

 

 

   

 

 

 

Basic and diluted net income per limited partner unit

   $ 0.50      $ 1.54      $ 1.17   
  

 

 

   

 

 

   

 

 

 

Weighted average number of units outstanding

     106,028        81,917        67,702   
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

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NATURAL RESOURCE PARTNERS L.P.

STATEMENTS OF PARTNERS’ CAPITAL

(In thousands, except unit data)

 

    Common Units     General
Partner
Amounts
    Holders
of Incentive
Distribution
Rights
Amounts
    Non-
Controlling

Interest
Amounts
    Accumulated
Other
Comprehensive
Income (Loss)
    Total  
    Units     Amounts            

Balance at December 31, 2008

    64,891,136      $ 719,341      $ 13,579      $ 11,069      $      $ (648   $ 743,341   

Distributions

           (144,766     (3,762     (39,607                   (188,135

Issuance of units for acquisitions, net

    4,560,000        93,908        1,981                             95,889   

Net income for the year ended December 31, 2009

           78,954        1,611        33,515                      114,080   

Loss on interest hedge

                                       51        51   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income

                                       51        114,131   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2009

    69,451,136      $ 747,437      $ 13,409      $ 4,977      $      $ (597   $ 765,226   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributions

           (174,709     (4,197     (30,943                   (209,849

Issuance of units, net

    36,576,700        110,217                                    110,217   

Capital contribution

                  2,350                             2,350   

Fees associated with elimination of IDRs

           (2,341                                 (2,341

Non-controlling interest

                                5,065               5,065   

Net income for the year ended December 31, 2010

           125,925        2,570        25,966                      154,461   

Loss on interest hedge

                                       51        51   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income

                                       51        154,512   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2010

    106,027,836      $ 806,529      $ 14,132      $      $ 5,065      $ (546   $ 825,180   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributions

           (230,080     (4,696            (52            (234,828

Non-controlling interest adjustment

                                (373            (373

Costs associated with equity transactions

           (141                                 (141

Non-controlling interest

                                998               998   

Net income for the year ended December 31, 2011

           52,945        1,081                             54,026   

Loss on interest hedge

                                       53        53   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income

                                       53        55,077   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2011

    106,027,836      $ 629,253      $ 10,517      $      $ 5,638      $ (493   $ 644,915   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

    For the Years Ended December 31,  
          2011                 2010                 2009        

Cash flows from operating activities:

     

Net income

  $ 54,026      $ 154,461      $ 114,080   

Adjustments to reconcile net income to net cash provided by operating activities:

     

Depreciation, depletion and amortization

    65,118        56,978        60,012   

Non-cash interest charge

    625        540        1,463   

Non-cash gain on reserve swap

    (2,990              

Gain on sale of assets

    (1,058              

Asset impairment

    161,336                 

Non-controlling interest

    998                 

Change in operating assets and liabilities:

     

Accounts receivable

    (6,951     (2,627     581   

Other assets

    90        (27     (67

Accounts payable and accrued liabilities

    854        468        (133

Accrued interest

    950        (489     3,850   

Deferred revenue

    31,277        42,491        26,264   

Accrued incentive plan expenses

    1,909        6,137        4,577   

Property, franchise and other taxes payable

    (610     762        42   
 

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

    305,574        258,694        210,669   
 

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

     

Acquisition of land, coal, other mineral rights and related intangibles

    (120,184     (166,382     (118,754

Acquisition or construction of plant and equipment

    (404     (5,994     (1,157

Proceeds from sale of assets

    5,500        1,580          
 

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

    (115,088     (170,796     (119,911
 

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

     

Proceeds from loans

    385,000        140,000        331,000   

Proceeds from issuance of units

           110,436          

Deferred financing costs

    (2,957            (661

Repayments of loans

    (210,519     (106,234     (168,235

Payment of obligation related to acquisitions

    (7,625     (9,169     (72,000

Costs associated with equity transactions

    (141     (219     (21

Fees associated with elimination of IDRs

           (2,341       

Distributions

    (234,828     (209,849     (188,135

Contributions by general partner

           2,350          
 

 

 

   

 

 

   

 

 

 

Net cash used in financing activities

    (71,070     (75,026     (98,052
 

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

    119,416        12,872        (7,294

Cash and cash equivalents at beginning of period

    95,506        82,634        89,928   
 

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

  $ 214,922      $ 95,506      $ 82,634   
 

 

 

   

 

 

   

 

 

 

Supplemental cash flow information:

     

Cash paid during the period for interest

  $ 47,653      $ 41,565      $ 34,710   
 

 

 

   

 

 

   

 

 

 

Non-cash investing activities:

     

Equity issued for acquisitions

  $      $      $ 95,910   

Assets contributed by general partner for acquisitions

                  1,981   

Liability assumed in acquisitions

           1,593        1,170   

Non-controlling interest

    373        (5,065       

Non-cash financing activities:

     

Purchase obligation related to reserve and infrastructure acquisitions

    500        6,200        74,022   

The accompanying notes are an integral part of these financial statements.

 

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Basis of Presentation and Organization

Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning and managing mineral properties in the United States. The Partnership owns coal reserves in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. As of December 31, 2011, the Partnership owned or controlled approximately 2.3 billion tons of proven and probable coal reserves (unaudited), and also owned approximately 380 million tons of aggregate reserves (unaudited) in a number of states across the country. The Partnership does not operate any mines, but leases reserves to experienced mine operators under long-term leases that grant the operators the right to mine reserves in exchange for royalty payments. Lessees are generally required to make royalty payments based on the higher of a percentage of the gross sales price or a fixed price per ton, in addition to a minimum payment.

In addition, the Partnership owns coal transportation and preparation equipment, other coal related rights and oil and gas properties on which it earns revenue.

The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through a wholly owned operating company, NRP (Operating) LLC. NRP (GP) LP, the general partner of the Partnership, has sole responsibility for conducting its business and for managing its operations. Because its 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 its behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson is entitled to nominate all nine of the directors, five of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC. In connection with the Cline acquisition, Mr. Robertson delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, LLC, an affiliate of the Cline Group.

2.    Summary of Significant Accounting Policies

Principles of Consolidation

The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries as well as BRP LLC, a venture with International Paper Company controlled by the Partnership. Intercompany transactions and balances have been eliminated.

Business Combinations

For purchase acquisitions accounted for as a business combination, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques.

Use of Estimates

Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Cash Equivalents and Restricted Cash

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.

Accounts Receivable

Accounts receivable from the Partnership’s lessees do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying consolidated balance sheets. The Partnership evaluates the collectability of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its lessees’ accounts and when it becomes aware of a specific customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. Accounts are charged off when collection efforts are complete and future recovery is doubtful. If circumstances related to specific lessees change, the Partnership’s estimates of the recoverability of receivables could be further adjusted.

Land, Coal and Mineral Rights

Land, coal and other mineral rights owned and leased are recorded at cost. Coal and other mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein, or over the amortization period of the lease.

Plant and Equipment

Plant and equipment consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at cost and are being depreciated on a straight-line basis over their useful lives, which range from three to twenty years.

Intangible Assets

The Partnership’s intangible assets consist of above-market contracts. Intangible assets are identified related to contracts acquired when compared to the estimate of current market rates for similar contracts. The estimated fair value of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis. In April 2010, the Partnership refined its accounting policy to reflect a minimum amortization to be applied in each period for temporarily idled assets.

Asset Impairment

If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.

Deferred Financing Costs

Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s revolving credit facility and senior notes. These costs are amortized over the term of the debt.

 

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Revenues

Coal and Aggregate Royalties.     Coal and aggregate royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell.

Processing and Transportation Fees.     Processing fees are recognized on the basis of tons of coal processed through the facilities by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, the Partnership receives a fixed price per ton for all material transported on the beltlines.

Oil and Gas Royalties.     Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Also, included within oil and gas royalties are lease bonus payments, which are generally paid upon the execution of a lease. Some are subject to minimum annual payments or delay rentals.

Minimum Royalties.     Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal or aggregate royalty revenue when the lessee recoups the minimum payment through production. The deferred revenue attributable to the minimum payments is recognized as minimums recognized as revenue when the period during which the lessee is allowed to recoup the minimum payment expires.

Property Taxes

The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in property tax revenue in the Consolidated Statements of Income.

Income Taxes

No provision for income taxes related to the operations of the Partnership has been included in the accompanying financial statements because, as a partnership, it is not subject to federal or material state income taxes and the tax effect of its activities accrues to the unitholders. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.

Share-Based Payment

The Partnership accounts for awards relating to its Long-Term Incentive Plan under FASB’s stock compensation authoritative guidance. This authoritative guidance provides that grants must be accounted for using the fair value method, which requires the Partnership to estimate the fair value of the grant and charge or credit the estimated fair value to expense over the service or vesting period of the grant based on fluctuations in value. In addition, this authoritative guidance requires that estimated forfeitures be included in the periodic computation of the fair value of the liability and that the fair value be recalculated at each reporting date over the service or vesting period of the grant.

 

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

New Accounting Standards

In June 2011, the FASB amended the presentation of comprehensive income. The amendments in this update give the Partnership the option to present the total comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. These amendments are effective for fiscal years and interim periods within those years, beginning on or after December 15, 2011. The Partnership has not determined which method of presentation it will elect.

In May 2011, the FASB amended fair value measurement and disclosure requirements. The amendments result in common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs). Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principal or requirement for measuring fair value or for disclosing information about fair value measurements. The amendment likely to have the most impact on the Partnership relates to the fair value disclosure of the senior notes’ quantitative information about unobservable inputs used in fair value measurements that is categorized within Level 3 of the fair value hierarchy. These amendments are effective for fiscal years and interim periods within those years, beginning on or after December 15, 2011. The Partnership does not expect this adoption to have a material impact on its financial position, results of operations or cash flows.

Other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

3.    Significant acquisitions

BRP LLC.     In June 2010, the Partnership and International Paper Company (“IPC”) formed BRP to own and manage mineral assets previously owned by IPC. Some of these assets are currently subject to leases, and certain other assets are available for future development by the venture. In exchange for a $42.5 million contribution, NRP became the controlling member with the right to designate two of the three managers of BRP. NRP has a 51% income interest plus a preferential cumulative annual distribution prior to profit sharing. In exchange for the contribution of the producing properties and the properties not currently producing, IPC received $42.5 million in cash, a minority voting interest and a 49% income interest after the preferential cumulative annual distribution. The amount of the preference is fixed throughout the life of the venture but can be reduced by a portion of the proceeds received from sales of producing properties included in the initial acquisition. Identified tangible assets included in the transaction are oil and gas, coal, and aggregate reserves, as well as the rights to other unidentified minerals which may include coal bed methane, geothermal, CO2 sequestration, water rights, precious metals, industrial minerals and base metals. Certain properties, including oil and gas, coal and aggregates, as well as land leased for cell towers, are currently under lease and generating revenues.

The transaction was accounted for as a business combination and the assets and liabilities of BRP are included in the consolidated balance sheet. The following table summarizes the final allocation of the purchase price fair values of the assets acquired and liabilities assumed for the BRP transaction:

 

    

Final

Fair Value
(In thousands)

 

Coal and other mineral rights

   $ 45,329   

Intangible assets

   $ 1,863   

Capital contribution

   $ 42,500   

Non-controlling interests

   $ 4,692   

 

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Approximately $38.3 million of the total $47.2 million asset fair value, as well as the value of the $4.7 million non-controlling interest, were estimated using an expected cash flows approach. The remaining assets fair value was determined using a Level 2 market approach.

Operations of the venture are included from June 1, 2010, the effective date of acquisition. Total net income from startup through December 31, 2010 was $2.3 million and for the year ended December 31, 2011 was $5.2 million. The venture operating agreement provides that net income of the venture only be allocated to the non-controlling interests after the preferential cumulative annual distribution.

Transaction expenses related to the acquisition through December 31, 2010 were $2.5 million. For the year ended December 31, 2011, transaction expenses were $0.6 million and are included in general and administrative expenses in the accompanying Consolidated Statements of Income.

Colt.     In September 2009, the Partnership signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the Cline Group, through several separate transactions for a total purchase price of $255 million. As of December 31, 2011, the Partnership had acquired approximately 92.1 million tons of reserves for approximately $175 million, including $70.0 million paid during the first quarter 2011. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine.

4.    Allowance for Doubtful Accounts

Activity in the allowance for doubtful accounts for the years ended December 31, 2011, 2010 and 2009 was as follows:

 

     2011     2010      2009  
     (In thousands)  

Balance, January 1

   $ 681      $ 372       $ 366   

Provision charged to operations:

       

Additions to the reserve

     71        309         37   

Collections of previously reserved accounts

     (359             (31
  

 

 

   

 

 

    

 

 

 

Total charged (credited) to operations

     (288     309         6   

Non-recoverable balances written off

                      
  

 

 

   

 

 

    

 

 

 

Balance, December 31

   $ 393      $ 681       $ 372   
  

 

 

   

 

 

    

 

 

 

5.    Asset Impairments

Gatling West Virginia.     In October 2011, the Partnership was informed by Gatling Ohio, LLC, a Cline affiliate, that it was idling the operations and was no longer projecting production from the West Virginia mine. The Partnership and Gatling have amended the lease with respect to this property to provide that the existing minimum royalty balance of $24.1 million is non-recoupable, that Gatling will pay $3.4 million in non-recoupable minimum royalties when they become due in January and April of 2012, that the minimums will be reduced after the first quarter of 2012, and that Gatling will continue to maintain and ventilate the mine. Considering all information available at that time, the Partnership determined that its investment in the Gatling West Virginia property was not fully recoverable by future cash flows. The assets include coal reserves, certain above market intangibles and coal transportation equipment.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The net book value as of the measurement date and calculated fair values of the assets relating to the Gatling West Virginia operation are as follows:

 

     Fair Value      Net Book
Value
 
     (In thousands)  

Coal and other mineral rights, net

   $ 6,618       $ 76,003   

Intangible assets, net

             43,855   

Plant and equipment, net

     2,600         7,775   
  

 

 

    

 

 

 

Total

   $ 9,218       $ 127,633   
  

 

 

    

 

 

 

The asset impairment of $118.4 million was offset by $24.1 million of recoupable minimum payments received from Gatling, LLC to date and $3.4 million in cash payments to be received, resulting in a net asset impairment of $90.9 million, which is included in operating costs and expenses on the Consolidated Statements of Income.

Gatling Ohio.    In December 2011, the Partnership was informed by Gatling, LLC, a Cline affiliate, that it was idling its operations and was no longer projecting production from the Ohio mine. Gatling Ohio’s recoupable minimum royalty balance as of December 31, 2011 was $9.6 million. Considering all information available at this time, the Partnership has determined that its investment in the Gatling Ohio property will not be fully recovered by future cash flows. The assets include coal reserves, certain above market intangibles and coal transportation equipment.

The net book value as of the measurement date and calculated fair values of the assets relating to the Gatling Ohio operation are as follows:

 

     Fair Value      Net Book
Value
 
     (In thousands)  

Coal and other mineral rights, net

   $ 20,035       $ 56,769   

Intangible assets, net

             33,670   

Plant and equipment, net

     2,947         2,947   
  

 

 

    

 

 

 

Total

   $ 22,982       $ 93,386   
  

 

 

    

 

 

 

The asset impairment of $70.4 million is included in operating costs and expenses on the Consolidated Statements of Income.

In determining impairments of the Gatling West Virginia and Gatling Ohio assets, the fair values of the coal rights were estimated using a weighted combination of Level 3 expected cash flow and Level 2 market approaches. The fair values of the transportation equipment were estimated using Level 2 market approaches. The expected cash flows were developed using estimated annual sales tons and administrative expenses, as well as forecasted sales prices and anticipated market royalty rates. The market approaches include references to recent comparable transactions that were adjusted for each mine’s specific characteristics. Since Gatling, LLC is no longer projecting production in the near term future for the West Virginia and Ohio properties, the related royalty and transportation contract intangible assets were estimated to have no fair value as of the measurement date.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

6.    Plant and Equipment

The Partnership’s plant and equipment consist of the following:

 

     December 31,
2011
    December 31,
2010
 
     (In thousands)  

Plant construction in process

   $ 78      $ 6,279   

Plant and equipment at cost

     67,175        81,906   

Less accumulated depreciation

     (21,068     (25,837
  

 

 

   

 

 

 

Net book value

   $ 46,185      $ 62,348   
  

 

 

   

 

 

 

 

     For the years ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Total depreciation expense on plant and equipment

   $ 8,589       $ 8,322       $ 7,998   
  

 

 

    

 

 

    

 

 

 

Under the provisions of one of the Partnership’s tipple leases, the lessee exercised its option to purchase the tipple and corresponding land for fair market value, which is greater than the carrying amount of the asset. In May 2011, the lessee paid a $1.0 million deposit that was nonrefundable. In August 2011, the lessee paid the remaining $4.5 million to complete the purchase of the tipple. The Partnership recognized a gain on the sale in the third quarter of $1.1 million, which is included in Other Revenue on the Consolidated Statements of Income.

7.    Coal and Other Mineral Rights

The Partnership’s coal and other mineral rights consist of the following:

 

     December 31,
2011
    December 31,
2010
 
     (In thousands)  

Coal and other mineral rights

   $ 1,645,451      $ 1,629,286   

Less accumulated depletion and amortization

     (387,950     (347,650
  

 

 

   

 

 

 

Net book value

   $ 1,257,501      $ 1,281,636   
  

 

 

   

 

 

 

 

     For the years ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Total depletion and amortization expense on coal and other mineral interests

   $ 47,230       $ 38,501       $ 48,591   
  

 

 

    

 

 

    

 

 

 

Included in depletion in 2009 is a charge of $8.2 million related to a terminated lease from a mine closure.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

8.    Intangible Assets

Amounts recorded as intangible assets along with the balances and accumulated amortization at December 31, 2011 and 2010 are reflected in the table below:

 

     December 31,
2011
    December 31,
2010
 
     (In thousands)  

Contract intangibles

   $ 89,420      $ 180,233   

Less accumulated amortization

     (14,258     (18,302
  

 

 

   

 

 

 

Net book value

   $ 75,164      $ 161,931   
  

 

 

   

 

 

 

 

     For the years ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Total amortization expense on intangible assets

   $ 9,298       $ 10,150       $ 3,423   
  

 

 

    

 

 

    

 

 

 

The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods.

 

Estimated amortization expense (In thousands)

  

For year ended December 31, 2012

   $ 3,766   

For year ended December 31, 2013

     4,664   

For year ended December 31, 2014

     4,500   

For year ended December 31, 2015

     4,500   

For year ended December 31, 2016

     4,500   

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

9.    Long-Term Debt

Long-term debt consists of the following:

 

    December 31,
2011
    December 31,
2010
 
    (In thousands)  

$300 million floating rate revolving credit facility, due August 2016

  $      $ 94,000   

5.55% senior notes, with semi-annual interest payments in June and December, maturing June 2013

    35,000        35,000   

4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018

    32,317        37,650   

8.38% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2013, maturing in March 2019

    150,000        150,000   

5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020

    69,230        76,923   

5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021

    1,922        2,115   

5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023

    33,600        36,900   

4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2023

    75,000          

5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024

    195,000        210,000   

8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024

    50,000        50,000   

5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026

    175,000          

5.18% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026

    50,000          
 

 

 

   

 

 

 

Total debt

    867,069        692,588   

Less — current portion of long term debt

    (30,801     (31,518
 

 

 

   

 

 

 

Long-term debt

  $ 836,268      $ 661,070   
 

 

 

   

 

 

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Principal payments due in:

 

     Senior Notes      Credit Facility      Total  
     (In thousands)  

2012

   $ 30,801       $       $ 30,801   

2013

     87,230                 87,230   

2014

     80,983                 80,983   

2015

     80,983                 80,983   

2016

     80,983                 80,983   

Thereafter

     506,089                 506,089   
  

 

 

    

 

 

    

 

 

 
   $ 867,069       $       $ 867,069   
  

 

 

    

 

 

    

 

 

 

The senior note purchase agreement contains covenants requiring our operating subsidiary to:

 

   

Maintain a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters;

 

   

not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and

 

   

maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

The 8.38% and 8.92% senior notes also provide that in the event that the Partnership’s leverage ratio exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.

During 2011, the Partnership issued $300 million of senior unsecured notes. Proceeds from the senior notes were used to repay all of the outstanding borrowings under the revolving credit facility and the Partnership has used, or will use, the remaining proceeds for acquisitions.

A summary of the four tranches of senior notes are as follows:

 

Series

  

Amount

     Interest Rate    

Issue Date

    

Maturity

 

H

     $75 million         4.73     April 20, 2011         December 1, 2023   

I

     $125 million         5.03     April 20, 2011         December 1, 2026   

J

     $50 million         5.03     June 15, 2011         December 1, 2026   

K

     $50 million         5.18     October 3, 2011         December 1, 2026   

All tranches have semi-annual interest payments beginning December 1, 2011, and equal annual principal payments beginning December 1, 2014.

The Partnership made principal payments of $31.5 million on its senior notes during the year ended December 31, 2011.

On August 10, 2011, the Partnership completed an amendment and restatement of its $300 million revolving credit facility. The amendment extends the term of the credit facility to August 2016. The Partnership incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.18% to 0.40% per annum. The facility includes an accordion feature whereby the Partnership may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

At December 31, 2011 the Partnership did not have any outstanding balance on its revolving credit facility, while at December 31, 2010 the Partnership had $94.0 million. The weighted average interest rates for the year ended December 31, 2011 and the year ended December 31, 2010 were 1.83% and 1.42%, respectively.

The revolving credit facility contains covenants requiring the Partnership to maintain:

 

   

a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and,

 

   

a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent quarters.

The Partnership was in compliance with all terms under its long-term debt as of December 31, 2011.

10.    Fair Value Measurements

The Partnership discloses certain assets and liabilities using fair value as defined by FASB’s fair value authoritative guidance.

FASB’s guidance describes three levels of inputs that may be used to measure fair value:

 

   

Level 1 — Quoted prices in active markets for identical assets or liabilities.

 

   

Level 2 — Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

 

   

Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of the Partnership’s accounts receivable and accounts payable approximates their fair value due to their short-term nature. The Partnership’s cash and cash equivalents include money market accounts and are considered a Level 1 measurement. The fair market value of the Partnership’s long-term debt was estimated to be $916.0 million and $596.1 million at December 31, 2011 and 2010, respectively, for the senior notes. The carrying value of the Partnership’s senior notes was $867.1 million and $598.6 million at December 31, 2011 and 2010, respectively. The fair value is estimated by management using comparable term risk-free treasury issues with a market rate component determined by current financial instruments with similar characteristics which is a Level 3 measurement. Since the Partnership’s credit facility is variable rate debt, its fair value approximates its carrying amount.

11.    Incentive Distribution Rights

On September 20, 2010, the Partnership eliminated all of the incentive distribution rights (IDRs) held by its general partner and affiliates of the general partner. As consideration for the elimination of the IDRs, the Partnership issued 32 million common units to the holders of the IDRs. As of the date of this report, there are 106,027,836 common units outstanding and the general partner has retained its 2% interest in the Partnership.

12.    Related Party Transactions

Reimbursements to Affiliates of our General Partner

The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates.

The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as follows:

 

     For the Years Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Reimbursement for services

   $ 9,136       $ 7,358       $ 6,822   
  

 

 

    

 

 

    

 

 

 

The Partnership leases substantially all of two floors of an office building in Huntington, West Virginia from Western Pocahontas Properties and pays $0.5 million in lease payments each year through December 31, 2018.

Transactions with Cline Affiliates

Various companies controlled by Chris Cline lease coal reserves from the Partnership, and the Partnership provides coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in the Partnership’s general partner, as well as 16,686,672 common units. At December 31, 2011, the Partnership had accounts receivable totaling $8.4 million from Cline affiliates. Revenues from the Cline affiliates are as follows:

 

     For The Year Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Coal royalty revenues

   $ 42,474       $ 32,407       $ 23,325   

Processing fees

     2,975         1,337         193   

Transportation fees

     16,689         14,324         11,495   

Minimums recognized as revenue

             12,400           

Override revenue

     2,691         1,904         2,356   
  

 

 

    

 

 

    

 

 

 
   $ 64,829       $ 62,372       $ 37,369   
  

 

 

    

 

 

    

 

 

 

As of December 31, 2011, the Partnership had received $47.2 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $20.2 million was received in the current year.

The Partnership recognized an asset impairment of $90.9 million during the third quarter of 2011 related to certain of the Partnership’s assets at the Gatling WV location and $70.4 million during the fourth quarter of 2011 related to certain assets at the Gatling Ohio location. These assets were acquired from and are leased by Cline affiliates.

The Partnership recognized a $3.0 million gain on a reserve exchange of over one million tons in Illinois with Williamson Energy. The fair value of the reserves was estimated using Level 3 cash flow approach. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates. The tons received will be fully mined during 2012, while the tons exchanged are not included in the current mine plans. The gain is located in Other revenues on the Consolidated Statements of Income.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Quintana Capital Group GP, Ltd.

Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in NRP’s conflicts policy.

A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. The Partnership currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. The Partnership owns and leases the plants to Taggart Global, which designs, builds and operates the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. To date, the Partnership has acquired four facilities under this agreement with Taggart with a total cost of $46.6 million. Revenues from Taggart are as follows:

 

     For the Years Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Processing revenue

   $ 9,755       $ 5,874       $ 3,872   
  

 

 

    

 

 

    

 

 

 

At December 31, 2011, the Partnership had accounts receivable totaling $1.3 million from Taggart.

A fund controlled by Quintana Capital owns Kopper-Glo, a small coal mining company that is one of the Partnership’s lessees with operations in Tennessee. Revenues from Kopper-Glo are as follows:

 

     For the Years Ended
December 31,
 
     2011      2010      2009  
     (In thousands)  

Coal royalty revenues

   $ 1,629       $ 1,545       $ 1,560   
  

 

 

    

 

 

    

 

 

 

At December 31, 2011, the Partnership also had accounts receivable totaling $0.1 million from Kopper-Glo.

13.    Commitments and Contingencies

Legal

The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.

Environmental Compliance

The operations conducted on the Partnership’s properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among

 

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other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties as of December 31, 2011. The Partnership is not associated with any environmental contamination that may require remediation costs.

Acquisition

In conjunction with a definitive agreement, as of December 31, 2011, the Partnership may be obligated to purchase in excess of 100 million additional tons of coal reserves from Colt, LLC for an aggregate purchase price of $80.0 million as certain milestones are completed relating to construction of a new mine. See Footnote 16 – “Subsequent Events”, for further information regarding an additional acquisition of reserves after December 31, 2011.

14.    Major Lessees

The Partnership has the following lessees that generated in excess of ten percent of total revenues in any one of the years ended December 31, 2011, 2010, and 2009. Revenues from these lessees are as follows:

 

     For the Years Ended
December 31,
 
     2011     2010     2009  
     Revenues      Percent