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EX-23.1 - EX-23.1 - NATURAL RESOURCE PARTNERS LPh69690exv23w1.htm
Table of Contents

 
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, 2009 or
o
  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
  77002
(Zip Code)
(Address of principal executive offices)    
 
(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 o
 
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 o     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 the filing requirements for the past 90 days.  Yes þ     No o
 
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 o     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.  o
 
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. (Check one):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes o 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 $0.8 billion on June 30, 2009 based on a price of $21.01 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 26, 2010, there were 69,451,136 Common Units outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE.
None.
 


 

 
Table of Contents
 
             
Item
      Page
 
1.
  Business     2  
1A.
  Risk Factors     12  
1B.
  Unresolved Staff Comments     22  
2.
  Properties     23  
3.
  Legal Proceedings     30  
4.
  Submission of Matters to a Vote of Security Holders     30  
 
5.
  Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities     31  
6.
  Selected Financial Data     33  
7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     34  
7A.
  Quantitative and Qualitative Disclosures About Market Risk     48  
8.
  Financial Statements and Supplementary Data     49  
9.
  Changes In and Disagreements with Accountants on Accounting and Financial Disclosure     69  
9A.
  Controls and Procedures     69  
9B.
  Other Information     70  
 
10.
  Directors and Executive Officers of the General Partner and Corporate Governance     71  
11.
  Executive Compensation     77  
12.
  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters     85  
13.
  Certain Relationships and Related Transactions, and Director Independence     86  
14.
  Principal Accounting Fees and Services     93  
 
15.
  Exhibits, Financial Statement Schedules     96  
 EX-21.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1


Table of Contents

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 and aggregates 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 and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2009, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves. We do not operate any mines, but lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal 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 of coal sold, in addition to minimum payments. As of December 31, 2009, our coal reserves were subject to 210 leases with 72 lessees. In 2009, our lessees produced 46.8 million tons of coal from our properties and our coal royalty revenues were $196.6 million.
 
Beginning in 2006, we added two new businesses: coal infrastructure and ownership of aggregate reserves that are leased to operators in exchange for royalty payments similar to our coal royalty business. During 2009, our lessees produced 3.3 million tons of aggregates and our aggregate royalties were $5.6 million, which includes a $1.3 million bonus payment under the terms of one of our leases. Coal processing fees and coal transportation fees added $7.7 million and $12.5 million in revenue, respectively.
 
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.
 
Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation and Great Northern Properties Limited Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the WPP Group. Mr. Robertson owns the general partner of Western Pocahontas Properties, 85% of the general partner of Great Northern Properties and is the Chairman and Chief Executive Officer of New Gauley Coal Corporation.
 
The senior executives and other officers who manage the WPP Group assets also manage us. They are employees of Western Pocahontas Properties and Quintana Minerals Corporation, another company 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.
 
Coal Royalty Business
 
Coal royalty businesses principally own and manage coal reserves. As an owner of coal reserves, we typically are not responsible for operating mines, but instead enter into leases with coal mine operators granting them the right to mine and sell coal 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.


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Table of Contents

Under our standard lease, lessees calculate royalty and wheelage payments due us and are required to report tons of coal removed or hauled across our property as well as the sales prices of coal. Therefore, to a great extent, amounts reported as royalty and wheelage 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 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 or wheelage revenue was initially recorded.
 
Coal royalty revenues are affected by changes in long-term and spot coal prices, lessees’ supply contracts and the royalty rates in our leases. The prevailing price for coal depends on a number of factors, including the supply-demand relationship, the price and availability of alternative fuels, global economic conditions and governmental regulations. 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 coal is produced.
 
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. 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 weather can cause a short-term decrease in coal production by our lessees due to the weather’s negative impact on production and transportation.
 
Acquisitions
 
We are a growth-oriented company and have closed 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, 2009, 2008 and 2007. Coal royalty revenues were generated from the properties in each of the areas as follows:
 
                                                 
          Average Coal Royalty
 
    Coal Royalty Revenues
    Revenue per Ton
 
    for the Years Ended
    for the Years Ended
 
    December 31,     December 31,  
    2009     2008     2007     2009     2008     2007  
    (In thousands)     ($ per ton)  
 
Area
                                               
Appalachia
                                               
Northern
  $ 14,959     $ 17,074     $ 16,664     $ 3.03     $ 2.94     $ 2.29  
Central
    132,543       156,109       117,820       4.73       4.34       3.29  
Southern
    19,382       19,839       17,832       6.00       4.64       3.87  
                                                 
Total Appalachia
    166,884       193,022       152,316       4.61       4.19       3.19  
Illinois Basin
    22,019       21,695       7,963       3.31       2.61       2.15  
Northern Powder River Basin
    7,718       11,533       11,064       1.94       1.85       1.90  
                                                 
Total
  $ 196,621     $ 226,250     $ 171,343     $ 4.20     $ 3.74     $ 2.99  
                                                 


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Table of Contents

The following table sets forth production data and reserve information for the properties that we owned or controlled for the years ending December 31, 2009, 2008, and 2007. 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 is as follows:
 
Production and Reserves
 
                                                 
    Production for the Year Ended
    Proven and Probable Reserves at
 
    December 31,     December 31, 2009  
    2009     2008     2007     Underground     Surface     Total  
    (Tons in thousands)  
 
Area
                                               
Appalachia
                                               
Northern
    4,943       5,799       7,270       503,086       6,642       509,728  
Central
    28,032       35,967       35,835       1,048,426       147,086       1,195,512  
Southern
    3,233       4,273       4,603       100,483       25,776       126,259  
                                                 
Total Appalachia
    36,208       46,039       47,708       1,651,995       179,504       1,831,499  
Illinois Basin
    6,656       8,313       3,709       188,639       15,123       203,762  
Northern Powder River Basin
    3,984       6,218       5,815             109,306       109,306  
                                                 
Total
    46,848       60,570       57,232       1,840,634       303,933       2,144,567  
                                                 
 
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, 2009, approximately 54% of our reserves were low sulfur coal and 35% 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 2009, approximately 26% of the production and 33% of the coal royalty revenues from our properties were from metallurgical coal.
 
The following table sets forth our estimate of the sulfur content, the typical quality of our coal reserves and the type of coal in each area as of December 31, 2009.
 
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
    42,873       51,452       23,929       434,347       509,728       12,875       2.72       500,166       9,562  
Central
    620,936       900,054       263,359       32,099       1,195,512       13,440       0.89       786,826       408,686  
Southern
    87,572       93,910       28,531       3,818       126,259       13,500       0.82       81,638       44,621  
                                                                         
Total Appalachia
    751,381       1,045,416       315,819       470,264       1,831,499                       1,368,630       462,869  
Illinois Basin
                3,314       200,448       203,762       11,550       2.86       203,762        
Northern Powder River Basin
          109,306                   109,306       8,800       0.65       109,306        
                                                                         
Total
    751,381       1,154,722       319,133       670,712       2,144,567                       1,681,698       462,869  
                                                                         


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(1) Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the Clean Air Act without blending with other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal.
 
(2) For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the metallurgical category can also be used as steam coal.
 
We have engaged Marshall Miller and Associates, Inc. and Stagg Resource Consultants, Inc. to conduct reserve studies of our existing properties. When we began this process, we focused primarily on reserves that were owned at the time. However, as a result of the extensive nature of our reserve holdings and the large number of acquisitions that we have completed, some of the more recent studies have been on properties that were subsequently acquired. These studies will be 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 acquisitions, we have either commissioned new studies or relied on recent reports done prior to the acquisition. In addition to these studies, we base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. Some of these factors and assumptions include:
 
  •  future coal prices, mining economics, capital expenditures, severance and excise taxes, and development and reclamation costs;
 
  •  future mining technology improvements;
 
  •  the effects of regulation by governmental agencies; and
 
  •  geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in other areas of our reserves.
 
As a result, actual coal tonnage recovered from identified reserve areas or properties may vary from estimates or may cause our estimates to change from time to time. Any inaccuracy in the estimates related to our reserves could result in royalties that vary from our expectations.
 
Coal Transportation and Processing Revenues
 
We own preparation plants and related coal handling facilities. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed. These facilities generated $7.7 million in coal processing revenues for 2009.
 
In addition to our preparation plants, we own coal handling and transportation infrastructure in West Virginia, Ohio and Illinois. For the year ended December 31, 2009, we recognized $12.5 million in revenue from these assets. For the assets other than 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 130 million tons of aggregate reserves that are principally located in Washington, Texas and Arizona. We also own a small number of aggregate reserves in West Virginia. We own a total of 56 million tons of reserves at our Washington property, but only approximately 11 million of those tons are currently permitted. If the remaining tons are not permitted by December 2016, the title to those tons reverts back to the seller. The Arizona (sand and gravel) and Texas (limestone) reserves were acquired in 2009. The Arizona aggregate reserves were acquired from an existing aggregate producer in December 2009, and are currently producing revenues. The Texas aggregate reserve acquisition was part of a greenfield development effort for a limestone quarry that will be operating and producing a royalty stream for us in


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mid-2010. During 2009, our lessees produced 3.3 million tons of aggregates, and our aggregate royalties were $5.6 million, which includes a $1.3 million bonus payment under the terms of one of our leases.
 
Oil and Gas Properties
 
In 2009, we derived approximately 3% of our total revenues from oil and gas royalties in Kentucky, Virginia and Tennessee.
 
Significant Customers
 
In 2009, Alpha Natural Resources and affiliates of the Cline Group each 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 us.
 
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 undergone significant consolidation since 1976. 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.
 
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


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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 technology and additional measures required under U.S. Environmental Protection Agency (or EPA) laws and 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 1997, the EPA promulgated a rule, referred to as the “NOx SIP Call,” that required coal-fired power plants and other large stationary sources in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule (or CAIR), which, if it remains in effect, would permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. CAIR will require these states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. 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, the CAIR was challenged and the Federal District Court of Appeals for the D.C. Circuit vacated the CAIR on July 11, 2008. North Carolina v. EPA, No. 05-1244 (D.C. Cir. Jul. 11, 2008). The vacatur caused significant uncertainty regarding state implementing regulations that were based on the CAIR. Upon request for reconsideration, though, the Court on December 23, 2008, subsequently revised its remedy to a remand to EPA without providing a response deadline. The EPA is expected to propose a revised rule in 2010 and complete its rule making in 2011. Accordingly, all state regulations that were based on the CAIR are still in effect, but we are unable to predict the outcome of EPA’s response to the remand and, therefore, unable to predict any effect on NRP.
 
In March 2005, the EPA finalized the Clean Air Mercury Rule (or CAMR), which establishes a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. The CAMR was vacated in early 2008 by the Federal Court of Appeals for the District of Columbia Circuit in State of New Jersey v. EPA, No. 05-1097 (D.C. Cir. Feb. 8, 2008) and the appeal process has not concluded. However, if fully implemented, CAMR would permit states to implement their own mercury control regulations or participate in an interstate cap-and-trade program for mercury emission allowances.
 
Continued tightening of the already stringent regulation of emissions is likely, such as EPA’s proposal published on December 8, 2009 to revise the national ambient air quality standard for oxides of sulfur and a similar proposal announced on January 6, 2010 for ozone. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. For example, in December 2004, the EPA designated specific areas in the United States as “non-attainment” areas, meaning that the designated areas failed to meet the new national ambient air quality standard for fine particulate matter. In May of 2007, EPA published a final rule requiring that each state having a nonattainment area submit to EPA by April 5, 2008, an attainment demonstration and adopt regulations ensuring that the area will attain the standards as expeditiously as practicable, but no later than 2015. The same process is being played out with respect to the new ozone standard, but with later attainment dates. Significant additional emission control expenditures will be required at coal-fueled power plants to meet the new standards for ozone.


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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 EPA issued a Finding of Failure to Submit plans on January 15, 2009 (74 Fed. Reg. 2392), which could trigger Federal plan implementation. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide and particulate matter.
 
Regulation of additional emissions such as carbon dioxide or other greenhouse gases as proposed or determined by EPA on October 27, October 30 and December 15, 2009 may eventually be applied to stationary sources such as coal-fueled power plants and industrial boilers (see discussion of Carbon Dioxide and Greenhouse Gas Emissions below). Coal mining operations emit particulate matter and coal-fired electric generating facilities emit all forms of pollutants regulated by the Clean Air Act. For this reason our lessees’ mining operations and their customers could be affected when these new standards are implemented by the applicable states, and their application could eventually reduce the demand for coal.
 
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 the mid-1990’s, the Kyoto Protocol to the United Nations Framework Convention on Climate Change called for developed nations to reduce their emissions of greenhouse gases to five percent below 1990 levels by 2012. Carbon dioxide, which is a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005 for those nations that ratified the treaty. The United States has not ratified the Kyoto Protocol, although it continues to participate actively in international discussions such as the December 2009 meeting in Copenhagen.
 
The United States Congress has begun considering multiple bills that would regulate domestic carbon dioxide emissions, but no such bill has yet received sufficient Congressional support for passage into law. The existing Clean Air Act is also a possible mechanism for regulating greenhouse gases. 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, in July 2008, the EPA issued a notice of proposed rulemaking requesting public comment on the regulation of greenhouse gases. On October 27, 2009 EPA announced how it will establish thresholds for phasing-in and regulating greenhouse gas emissions under various provisions of the Clean Air Act. Three days later, on October 30, 2009, EPA published a final rule in the Federal Register 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. On December 15, 2009, EPA published a formal determination that six greenhouse gases, including carbon dioxide and methane, endanger both the public health and welfare of current and future generations. In the same Federal Register rulemaking, EPA found that emission of greenhouse gases 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 greenhouse gas emissions from stationary sources, such as coal-fueled power plants, the decision is likely to impact regulation of stationary sources.
 
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. For example, in December 2005, seven northeastern states agreed to implement a regional cap-and-trade program to stabilize carbon


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dioxide emissions from regional power plants beginning in 2009. In addition, a challenge in the U.S. Court of Appeals for the District of Columbia with respect to the EPA’s decision not to regulate greenhouse gas emissions from power plants and other stationary sources under the Clean Air Act’s new source performance standards was remanded to the EPA for further consideration in light of Massachusetts v. EPA. The U.S. Court of Appeals for the Second Circuit has heard oral argument in a public nuisance action filed by eight states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) and New York City to curb carbon dioxide emissions from power plants. The parties have filed post-argument briefs on the impact of the Massachusetts v. EPA decision, and a decision is currently pending. 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 (or SMCRA) and similar state statutes 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 approved reclamation plan. In addition, higher and better uses of the reclaimed property are encouraged. Regulatory authorities 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 (or 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 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 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 impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants such as from spill or leak incidents is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of fill material and certain other activities in wetlands unless authorized by an appropriately issued permit.
 
Our lessees’ mining operations are strictly regulated by the Clean Water Act, particularly with respect to the discharge of overburden and fill material into waters, including wetlands. Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. A July 2004 decision by the federal court for the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington


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District of the U.S. Army Corps of Engineers from issuing further permits pursuant to Nationwide Permit 21, which is a general permit issued by the U.S. Army Corps of Engineers to streamline the process for obtaining permits under Section 404 of the Clean Water Act. While the decision was reversed and remanded to district court by the Fourth Circuit Court of Appeals in November 2005, the district court is currently considering additional challenges to Nationwide Permit 21. Additionally, a similar lawsuit filed in federal district court in Kentucky seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the U.S. Army Corps of Engineers. In the event that such lawsuits prove to be successful, some of our lessees may be required to apply for individual discharge permits pursuant to Section 404 of the Clean Water Act in areas where they would have otherwise utilized Nationwide Permit 21.
 
Aside from these lawsuits, on July 15, 2009, the Corps proposed to immediately suspend the use of the Nationwide Permit 21 in six Appalachian states, including West Virginia, Kentucky and Virginia, where our lessees conduct operations. In the same notice, the Corps proposed to modify the Nationwide Permit 21 following the receipt and review of public comments to prohibit its further use in the same states during the remaining term of the permit, which is March 12, 2012. The Corps is now reviewing the more than 21,000 public comments it has received. The agency has not announced when it is expected to complete its review and reach a final decision.
 
Regardless of the outcome of the Corps’ decision about any continuing use of Nationwide Permit 21, it does not prevent our lessees from seeking an individual permit under § 404 of the Clean Water Act, nor does it restrict an operation from utilizing another version of the nationwide permit authorized for small underground coal mines that must construct fills as part of their mining operations. Nevertheless, such changes will 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. Moreover, such individual permits are also subject to challenge.
 
In 2007, two decisions by the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Strock complicated the ability of our lessees both to obtain individual permits from the Corps of Engineers without performing a full environmental impact statement and to construct in-stream sediment ponds to control sediment from their excess spoil valley fills. The first decision, dated March 23, 2007 rescinded four individual permits issued to Massey Energy Company subsidiaries as a result of the Corps’ failure to properly evaluate the impacts of filling on small headwater streams and to ensure such impacts were appropriately minimized with mitigation efforts. This order has had the effect of slowing the flow of new “fill” permits from the Corps’ Huntington, West Virginia, District Office.
 
The second order, dated June 13, 2007, ruled that discharges of sediment from valley fills into sediment ponds constructed in-stream to collect and treat that sediment must meet the same standards as are applied to discharges from these sediment ponds. Because of the rugged terrain in central Appalachia, often the only practicable location for these ponds is in streams. The effect of the ruling is not yet clear, but it may require our lessees to disturb substantially more surface area to construct sediment structures out of the stream channels. A similar lawsuit (Kentucky Waterways Alliance, Inc. v. United States Army Corps of Engineers, Civil Action No. 3:07-cv-00677 (W.D. Ky. 2007)) was filed in the Western District of Kentucky and may affect future permitting by the Louisville, Kentucky District Office as well.
 
The Fourth Circuit reversed both orders on February 13, 2009, but the plaintiffs then asked the United States Supreme Court to review the decision. Although Massey and the other coal industry Intervenors in the case prefer the Court not to hear the case, neither the Corps nor the Intervenors have filed any response to the Plaintiffs petition because of an extension of the response deadline sought by the Corps. It is likely that the Corps and the Plaintiffs are in discussions that will result in the case being moot. If the Fourth Circuit decision stands, then a backlog of permits pending before the Corps of Engineers may ease.
 
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 which 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


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reclamation. In The West Virginia Highlands Conservancy, Plaintiff, v. Dirk Kempthorne, Secretary of the Department of the Interior, et al., Defendants, and the West Virginia Coal Association, Intervenor/Defendant, Civil Action No. 2:00-cv-1062 (United States District Court for the Southern District of West Virginia), an environmental group is claiming that the SRF is underfunded and that the Federal Office of Surface Mining (OSM) has an obligation under the Federal Surface Mining Act 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 Advisory Council” regarding the establishment of a $175 million trust fund for water treatment at future bond forfeiture sites has not been approved. A one-year increase in the reclamation tax was enacted in the 2008 Legislative Session. Following this legislative action, the plaintiff moved the Court to defer ruling on its motion to reopen the case until it is determined whether the increase will be re-enacted and whether it will be sufficient if West Virginia Department of Environmental Protection (“WVDEP”) is required to obtain National Pollution Discharge Elimination System (“NPDES”) permits at 21 bond forfeiture sites — relief sought in two separate citizens suits pending against WVDEP. In a May 15, 2008 Order, the Court denied plaintiff’s 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. In a companion case, West Virginia Highlands Conservancy v. Huffman, Civil Action No. 1:07-cv-87 (United States District Court, Northern District of West Virginia), the Court granted summary judgment on January 14, 2009 and required the WVDEP to obtain NPDES permits for bond forfeiture sites in the northern part of West Virginia. The WVDEP, joined by other states has appealed this decision to the Fourth Circuit.
 
If the Court ultimately rules that OSM has an obligation either to assume federal control of the State bonding program or 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.
 
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.
 
The Federal Safe Drinking Water Act (or 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


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of additional mine rescue teams, and expands the scope of federal oversight, inspection and enforcement activities. Earlier, the federal Mine Safety and Health Administration 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 are required for mining operations. In connection with obtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.
 
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for reclaiming the mined property, upon the completion of mining operations. 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, 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 71 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 mineral properties 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. We consider revenues from timber and oil and gas acquired as part of the acquisition of our mineral reserves to be incidental to our business focus and those revenues constitute less than 10% of our total revenues and assets. We anticipate that these assets will continue to be incidental to our primary business in the future.
 
Website Access to Company Reports
 
Our internet address is www.nrplp.com. We make available free of charge on or through our internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Also included on our website are our “Code of Business Conduct and Ethics”, our “Disclosure Controls and Procedures Policy” and our “Corporate Governance Guidelines” adopted by our Board of Directors 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 other factors beyond their or our control, including:
 
  •  the supply of and demand for domestic and foreign coal;
 
  •  domestic and foreign governmental regulations and taxes;


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  •  the price and availability of alternative fuels;
 
  •  the proximity to and capacity of transportation facilities;
 
  •  weather conditions; and
 
  •  the effect of worldwide energy conservation measures.
 
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.
 
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 2009, approximately 26% of the coal production and 33% 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 close. The steel industry has increasingly relied on electric arc furnaces or pulverized coal processes to make steel. If this trend continues, the amount of metallurgical coal that our lessees mine could decrease.
 
The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs for our lessees and reduced demand for our coal.
 
In April 2009, the Environmental Protection Agency, or “EPA,” issued a notice of its findings and determination that emissions of carbon dioxide, methane, and other “greenhouse gases,” or “GHGs,” presented an endangerment to human health and the environment because such gases are, according to EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Finalization of EPA’s finding and determination will allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. In September 2009, EPA proposed two sets of regulations in response to its finding and determination, one to reduce emissions of GHGs from motor vehicles and the other to control emissions from large stationary sources, including coal-fired electric power plants. Any limitation on emissions of GHGs from the operations of consumers of coal could cause them to incur additional costs and reduce the demand for coal.
 
On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as coal.
 
The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as


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needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could have an adverse effect on the demand for our coal. Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs. Most of the state-level initiatives to date have been focused on large sources of GHGs, such as coal-fired electric power plants. These state initiatives also could have an adverse effect on the demand for our coal.
 
In addition, two federal Courts of Appeals recently allowed lawsuits in which the plaintiffs assert common law causes of action, including that emissions of GHGs constitute a nuisance, to proceed against certain entities, including in one of the cases, Natural Resource Partners. The courts’ rulings could prompt additional similar litigation. An adverse outcome for the defendants in these or other similar cases could adversely affect the demand for our coal.
 
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 different permits, any of which could decrease our royalty revenues.
 
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 and pay distributions to our unitholders.
 
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.


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Due to these factors, 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.
 
Some of our lessees may be adversely impacted by the instability of the credit markets.
 
Many of our lessees finance their activities through cash flow from operations, the incurrence of debt, the use of commercial paper or the issuance of equity. Recently, there has been a significant deterioration in the credit markets and the availability of credit. The lack of availability of debt or equity financing may result in a significant reduction in our lessees’ spending related to development of new mines or expansion of existing mines on our properties. It may also impact our lessees’ ability to pay current obligations and continue ongoing operations on our properties. Any significant reductions in spending related to our lessees’ operations could have a material adverse effect on our revenues and ability to pay our quarterly distributions.
 
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 of 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.
 
There have been several recent lawsuits filed in Central Appalachia that will potentially make it much more difficult for our lessees to obtain permits to mine our coal. The most likely impact of the litigation will be 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 may increase our lessees’ cost of mining and delay or halt production at particular mines for varying lengths of time or permanently. Any interruptions to the production of coal from our reserves may reduce our coal royalty revenues.
 
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:
 
  •  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 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 do not generally 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 coal infrastructure business exposes us to risks that we do not experience in the royalty business.
 
Over the past three years, we have acquired several coal 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 operating risks associated with the transportation infrastructure at two mines. 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.
 
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


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partner may not be removed except upon the vote of the holders of at least 662/3% 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
 
  •  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 NYSE rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units without unitholder approval (subject to applicable NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •  an existing unitholder’s proportionate ownership interest in NRP will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
 
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
 
If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.
 
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
 
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
 
Conflicts of interest could arise among our general partner and us or the unitholders.
 
These conflicts may include the following:
 
  •  we do not have any employees and we rely solely on employees of affiliates of the general partner;


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  •  under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;
 
  •  the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly distributions to unitholders;
 
  •  the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability;
 
  •  under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arms 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.
 
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.


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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 has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be 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.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
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 with 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 with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be 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 decrease 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 portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your 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.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises 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 at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our


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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.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt 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, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.
 
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.
 
We will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.


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A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
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 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 currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for 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.
 
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.
 
Among the changes contained in the President’s Budget Proposal for Fiscal Year 2011 is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would (i) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties, and (iv) exclude 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. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could 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 may become 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 will likely be subject to other taxes, including foreign, 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 will likely be required to file foreign, 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, foreign, 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 2009, 2.2 million tons were produced from this property. We lease this property to Mettiki Coal, LLC, a subsidiary of Alliance Resource Partners L.P. Coal is produced from an underground longwall mine. It is transported by truck to a preparation plant operated by the lessee. Coal is shipped primarily by truck to the Mount Storm power plant of Dominion Power.
 
Gatling WV.  The Gatling property is located in Mason County, West Virginia. In 2009, 406,000 tons were produced from the property. Coal from this property is mined from an underground mine and transported via belt line to a preparation plant on the property. Clean coal is transported via beltline either directly to American Electric Power or to a barge loading facility.
 
AFG-Southwest PA.  The AFG property is located in Washington County, Pennsylvania. In 2009, 304,000 tons were produced from this property. We lease this property to Conrhein Coal Company, a subsidiary of Consol Energy. Coal is produced from an underground mine and is transported by belt to a preparation plant operated by the lessee. Coal is shipped by both the CSX and Norfolk Southern railways to utility customers, such as American Electric Power and Allegheny Energy.
 
Gatling OH.  The Gatling property is located in Meigs County, Ohio and was acquired in May 2009. From the date of acquisition through the remainder of the year, 277,000 tons were produced from the property. Coal from this property is mined from an underground mine and transported via belt line to a preparation plant on the property. Clean coal is transported via beltline to a barge loading facility, from which it is transported via barge to American Electric Power.
 
The map on the following page 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 2009, 4.9 million tons were produced from this property. We primarily lease this property to Alpha Land and Reserves, LLC, a subsidiary of Alpha Natural Resources, Inc. Production comes from both underground and surface mines and is trucked to one of four preparation plants. Coal is shipped via both the CSX and Norfolk Southern railroads to utility and metallurgical customers. Major customers include American Electric Power, Southern Company, Tennessee Valley Authority, VEPCO and U.S. Steel and to various export metallurgical customers.
 
Lynch.  The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2009, 4.1 million tons were produced from this property. We primarily lease the property to Resource Development, LLC, an independent coal producer. Production comes from both underground and surface mines. Coal is transported

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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.
 
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 2009, 3.2 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 customers such as American Electric Power and to various export metallurgical customers.
 
Dingess-Rum.  The Dingess-Rum property is located in Logan, Clay and Nicholas Counties, West Virginia. This property is leased to subsidiaries of Massey Energy and Patriot Coal. In 2009, 3.0 million tons were produced from the property. Both steam and metallurgical coal are produced from underground and surface mines and 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 2009, 2.6 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 2009, 1.8 million tons were produced from this property. We lease the property to Ark Land Company, 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.
 
Pardee.  The Pardee property is located in Letcher County, Kentucky and Wise County Virginia. In 2009, 1.4 million tons were produced from this property. We lease the property to Ark Land Company, 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.
 
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, Tennessee, and Alabama. In 2009, 2.4 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 2009, 858,000 tons were produced from this property. We lease the property to Oak Grove Resources, LLC, 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.


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The map below shows the location of our properties in Southern Appalachia.
 
 
Illinois Basin
 
Williamson Development.  The Williamson Development property is located in Franklin and Williamson Counties, Illinois. The property is under lease to an affiliate of the Cline Group, and in 2009, 5.5 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.
 
Sato.  The Sato property is located in Jackson County, Illinois. In 2009, 567,000 tons were produced from the property. The property is under lease to Knight Hawk Coal LLC, an independent coal producer. Production is currently from a surface mine, and coal is shipped by truck and railroad to various midwest and southeast utilities.
 
Macoupin.  The Macoupin property is located in Macoupin County, Illinois. We acquired this property in January 2009 and it is leased to an affiliate of the Cline Group. In 2009, 94,000 tons were shipped from the


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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.
 
The map below shows the location of our properties in Illinois Basin.
 
 
Northern Powder River Basin
 
Western Energy.  The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2009, 4.0 million tons were produced from our property. Western Energy Company, a subsidiary of Westmoreland Coal Company, has two coal leases on the property. Western Energy produces coal 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 on the following page shows the location of our properties in Northern Powder River Basin.
 


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Title to Property
 
Of the approximately 2.1 billion tons of proven and probable coal reserves that we owned or controlled as of December 31, 2009, we owned approximately 99% of the reserves in fee. We lease approximately 2 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.

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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.   Submission of Matters to a Vote of Security Holders
 
None.


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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 New York Stock Exchange (NYSE) under the symbol “NRP”. As of February 11, 2010, there were approximately 30,700 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 New York Stock Exchange Composite Transaction Tape from January 1, 2008 to December 31, 2009, and the quarterly cash distribution declared and paid with respect to each quarter per common unit.
 
                                         
                Cash Distribution History  
    Price Range     Per
    Record
    Payment
 
    High     Low     Unit     Date     Date  
 
2008
                                       
First Quarter
  $ 33.99     $ 24.61     $ 0.4950       05/01/2008       05/14/2008  
Second Quarter
  $ 41.65     $ 28.42     $ 0.5150       08/01/2008       08/14/2008  
Third Quarter
  $ 41.20     $ 22.75     $ 0.5250       11/03/2008       11/14/2008  
Fourth Quarter
  $ 25.99     $ 12.66     $ 0.5350       02/05/2009       02/13/2009  
2009
                                       
First Quarter
  $ 25.00     $ 17.59     $ 0.5400       05/04/2009       05/14/2009  
Second Quarter
  $ 25.47     $ 20.51     $ 0.5400       08/05/2009       08/14/2009  
Third Quarter
  $ 23.60     $ 17.00     $ 0.5400       11/05/2009       11/13/2009  
Fourth Quarter
  $ 24.81     $ 19.50     $ 0.5400       02/05/2010       02/12/2010  
 
Our general partner holds 65% of our incentive distribution rights (IDRs) and the remaining IDRs are held by affiliates of our general partner. The IDRs entitle the holders to incentive distributions if the amount we distribute with respect to any quarter exceeds the specified target levels shown below:
 
Percentage Allocations of Available Cash from Operating Surplus
 
                             
    Total Quarterly
  Marginal Percentage Interest in
 
    Distribution Target
  Distributions Paid  
    Amount   Unitholders     General Partner     Holders of IDRs  
 
Minimum Quarterly Distribution
  $0.25625     98 %     2 %      
First Target Distribution
  $0.25625 up to $0.28125     98 %     2 %      
Second Target Distribution
  above $0.28125 up to $0.33125     85 %     2 %     13 %
Third Target Distribution
  above $0.33125 up to $0.38125     75 %     2 %     23 %
Thereafter
  above $0.38125     50 %     2 %     48 %


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Cash Distributions to Partners
 
                                 
    General
    Limited
          Total
 
    Partner     Partners     IDRs     Distributions  
          (In thousands)        
 
2007
                               
Distributions
  $ 2,939     $ 118,858     $ 25,236     $ 147,033  
2008
                               
Distributions
    3,426       131,080       36,801       171,307  
2009
                               
Distributions
    3,762       144,766       39,607       188,135  
 
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.
 
In general, we intend to increase our cash distributions in the future assuming we are able to increase our “available cash” from operations and through acquisitions, provided there is no adverse change in operations, economic conditions and other factors. However, we cannot guarantee that future distributions will continue at such levels.


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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.” 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.
 
                                         
    For the Years Ended December 31,  
    2009     2008     2007     2006     2005  
    (In thousands, except per unit and per ton data)  
 
Income Statement Data:
                                       
Revenues:
                                       
Coal royalties and related revenues
  $ 207,138     $ 238,834     $ 177,088     $ 150,791     $ 145,990  
Coal processing and transportation
    20,190       20,437       8,808       1,452        
Aggregate royalties
    5,580       9,119       7,434       538        
Oil and gas royalties
    7,520       7,902       4,930       4,220       3,180  
Property taxes
    11,636       9,800       10,285       5,971       6,516  
Other
    4,020       5,573       6,440       7,701       3,367  
                                         
Total revenues
    256,084       291,665       214,985       170,673       159,053  
Expenses:
                                       
Depreciation, depletion and amortization
    60,012       64,254       51,391       29,695       33,730  
General and administrative
    23,102       13,922       20,048       15,520       12,319  
Property, franchise and other taxes
    14,996       13,558       13,613       8,122       8,142  
Other
    3,999       2,924       1,634       1,560       3,392  
                                         
Total expenses
    102,109       94,658       86,686       54,897       57,583  
                                         
Income from operations
    153,975       197,007       128,299       115,776       101,470  
Other, net
    (39,895 )     (27,001 )     (25,800 )     (13,686 )     (9,631 )
                                         
Net income
  $ 114,080     $ 170,006     $ 102,499     $ 102,090     $ 91,839  
                                         
Balance Sheet Data (at period end):
                                       
Land, equipment, coal and other mineral rights, net
  $ 1,405,083     $ 1,174,067     $ 1,222,094     $ 845,531     $ 610,506  
Total assets
    1,523,590       1,301,340       1,320,031       939,493       684,996  
Long-term debt
    626,587       478,822       496,057       454,291       221,950  
Partners’ capital
    765,226       743,341       744,591       435,687       425,908  
Other Data:
                                       
Royalty coal tons produced by lessees
    46,848       60,570       57,232       52,092       53,606  
Average gross coal royalty revenue per ton
  $ 4.20     $ 3.74     $ 2.99     $ 2.84     $ 2.65  
Aggregate tons produced by lessee
    3,269       4,791       5,698       412        
Average gross aggregate royalty revenue per ton
  $ 1.30     $ 1.31     $ 1.19     $ 1.11        
Basic and diluted net income per limited partner unit
  $ 1.17     $ 1.95     $ 1.11     $ 1.60     $ 1.71  
Weighted average number of units outstanding
    67,702       64,891       64,505       50,682       50,682  
Distributions per limited partner unit
  $ 2.16     $ 2.07     $ 1.88     $ 1.67     $ 1.45  


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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 coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2009, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves, of which 54% are low sulfur coal. We also owned approximately 130 million tons of aggregate reserves in Washington, Texas, Arizona and West Virginia. We 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 at approximately 3.5% per year. Over the long term, both our coal and aggregate royalty revenues are affected by changes in the market for and the market price of the commodities.
 
In our royalty business, our lessees 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 (usually two to five years) 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 21% of our 2009 revenues from other sources, as compared to 19% in 2008. These other sources include: coal processing and transportation fees; overriding royalties; royalties on oil and gas; wheelage payments; rentals; property tax revenue; minimums received as revenue; and timber.
 
Our Current Liquidity Position
 
As of December 31, 2009, we had $272 million in available capacity under our existing credit facility, which does not mature until March 2012, as well as approximately $82.6 million in cash. Following our recent acquisitions of additional reserves at the Blue Star mine in Texas and the Deer Run mine in Illinois in January 2010, we currently have $229 million in available capacity under our credit facility.
 
In connection with our acquisition of approximately 200 million tons of coal reserves related to the Deer Run mine in Illinois from Colt, LLC in the third quarter of 2009, the holders of our incentive distribution rights agreed to forego approximately $7.35 million in distributions with respect to each of the third and fourth quarters of 2009. In addition, because we amortize substantially all of our long-term debt, we have no need to pay off or refinance any debt obligations other than our regularly scheduled principal payments. For more information regarding this acquisition from Colt, LLC, please see “Recent Acquisitions”.
 
Pursuant to the purchase and sale agreement in connection with the Colt acquisition, we expect to fund an additional $205 million over the next two years, of which approximately $125 million is anticipated to be funded over the next 12 months, as the operator achieves various development milestones. We anticipate funding these acquisitions through the use of the available capacity under our credit facility and through the


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issuance of debt and/or equity in the capital markets. We believe that we have enough liquidity to meet our current capital needs.
 
Current Results
 
As of December 31, 2009, our coal and aggregate reserves were subject to 214 leases with 76 lessees. For the year ended December 31, 2009, our lessees produced 50.1 million tons of coal and aggregates, generating $202.2 million in royalty revenues from our properties, and our total revenues were $256.1 million.
 
As a result of declines in production in 2009, we recorded lower than expected revenues for 2009. The difficult economic environment hurt the aggregates business across the country and impacted demand for electricity, particularly within heavily industrialized regions where coal is the dominant generating fuel. In addition, low prices for natural gas in 2009 caused some utilities to displace coal with natural gas. While we do not have much visibility into the future of the coal markets, several public coal companies have indicated that they are starting to see signs of a recovery, and the cold winter has reduced the stockpiles at the utilities and increased natural gas prices. Because approximately 33% of our coal royalty revenues and 26% of the related production during 2009 were from metallurgical coal, we also felt the effects of the global reduction in demand for steel. Several of the metallurgical coal producers on our properties temporarily ceased production during the second quarter, but gradually started calling miners back to work in the third quarter of the year. We anticipate that metallurgical coal prices should continue to increase over 2010 and expect that during 2010 we will experience gradual improvements similar to the changes we saw in the latter part of 2009.
 
Even though coal royalty revenues from our Appalachian properties represented 65% of our total revenues in 2009, this percentage has continued to decline as we are diligently working to diversify our holdings by expanding our presence in the Illinois Basin and through additional aggregates acquisitions. Through our relationship with the Cline Group, we expect our Illinois Basin assets to contribute even more significantly to our total revenues in 2010.
 
Political, Legal and Regulatory Environment
 
The political, legal and regulatory environment is becoming increasingly difficult for the coal industry. In June 2009, the White House Council on Environmental Quality announced a Memorandum of Understanding among the Environmental Protection Agency, or “EPA”, Department of Interior, and the U.S. Army Corps of Engineers concerning the permitting and regulation of coal mines in Appalachia. While the Council described this memorandum as an “unprecedented step[s] to reduce environmental impacts of mountaintop coal mining,” the memorandum broadly applies to all forms of coal mining in Appalachia. The memorandum contemplates both short-term and long-term changes to the process for permitting and regulating coal mines in Appalachia.
 
These new processes, as yet undefined by EPA, impact only six Appalachian states. In connection with this initiative, the EPA has used its authority to create significant delays in the issuance of new permits and the modification of existing permits. The all-encompassing nature of the changes suggests that implementation of the memorandum will generate continued uncertainty regarding the permitting of coal mines in Appalachia for some time and inevitably will lead, at a minimum, to substantial delays and increased costs.
 
In addition to the increased oversight of the EPA, the Mine Safety and Health Administration, or MSHA, has increased its involvement in the approval of plans and enforcement of safety issues in connection with mining. 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 United States Congress has been considering multiple bills that would regulate domestic carbon dioxide emissions, but no such bill has yet received sufficient Congressional support for passage into law. The existing Clean Air Act is also a possible mechanism for regulating greenhouse gases. 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, in July 2008, the EPA issued a notice of proposed rulemaking requesting public comment on the regulation of greenhouse gases, or


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“GHGs”. On October 27, 2009 EPA announced how it will establish thresholds for phasing-in and regulating greenhouse gas emissions under various provisions of the Clean Air Act. Three days later, on October 30, 2009, EPA published a final rule in the Federal Register 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. On December 15, 2009, EPA published a formal determination that six greenhouse gases, including carbon dioxide and methane, endanger both the public health and welfare of current and future generations. In the same Federal Register rulemaking, EPA found that emission of greenhouse gases 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 greenhouse gas emissions from stationary sources, such as coal-fueled power plants, the decision is likely to impact regulation of stationary sources.
 
On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of GHGs in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as coal.
 
The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. The President has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could have an adverse effect on demand for our coal.
 
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 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,  
    2009     2008     2007  
 
Net cash provided by operating activities
  $ 210,669     $ 229,956     $ 168,153  
Less scheduled principal payments
    (17,235 )     (17,234 )     (9,350 )
Less reserves for future principal payments
    (32,235 )     (17,235 )     (13,388 )
Add reserves used for scheduled principal payments
    17,235       17,234       9,400  
                         
Distributable cash flow
  $ 178,434     $ 212,721     $ 154,815  
                         


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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.
 
AzConAgg.  In December 2009, we acquired approximately 230 acres of mineral and surface rights related to sand and gravel reserves in southern Arizona from a local operator for $3.75 million.
 
Colt.  In September 2009, we 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 eight separate transactions for a total purchase price of $255 million. Upon closing of the first transaction, we paid $10.0 million, funded through our credit facility, and acquired approximately 3.3 million tons of reserves associated with the initial production from the mine. In January 2010, we closed the second transaction for $40.0 million, funded through our credit facility, and acquired approximately 19.5 million tons of reserves. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.
 
Blue Star.  In July 2009, we acquired approximately 121 acres of limestone reserves in Wise County, Texas from Blue Star Materials, LLC for a purchase price of $24 million. As of December 31, 2009, we had funded $21.0 million of the acquisition with cash and borrowings under our credit facility. The remaining payment of $3.0 million was funded in January 2010.
 
Gatling Ohio.  In May 2009, we completed the purchase of the membership interests in two companies from Adena Minerals, LLC, an affiliate of the Cline Group. The companies own 51.5 million tons of coal reserves and infrastructure assets at Cline’s Yellowbush Mine located on the Ohio River in Meigs County, Ohio. We issued 4,560,000 common units to Adena Minerals in connection with this acquisition. In addition, the general partner of NRP granted Adena Minerals an additional nine percent interest in the general partner as well as additional incentive distribution rights.
 
Massey.  Jewell Smokeless.  In March 2009, we acquired from Lauren Land Company, a subsidiary of Massey Energy, the remaining four-fifths interest in coal reserves located in Buchanan County, Virginia in which we previously held a one-fifth interest. Total consideration for this purchase was $12.5 million.
 
Macoupin.  In January 2009, we acquired approximately 82 million tons of coal reserves and infrastructure assets related to the Shay No. 1 mine in Macoupin County, Illinois for $143.7 million from Macoupin Energy, LLC, an affiliate of the Cline Group.
 
Coal Properties.  In October 2008, we acquired an overriding royalty for $5.5 million from Coal Properties Inc. This overriding royalty agreement is for coal reserves located in the states of Illinois and Kentucky.
 
Mid-Vol Coal Preparation Plant.  In April 2008, we completed construction of a coal preparation plant and coal handling infrastructure under our memorandum of understanding with Taggart Global USA, LLC. The total cost to build the facilities was $12.7 million.
 
Licking River Preparation Plant.  In March 2008, we signed an agreement for the construction of a coal preparation plant facility under our memorandum of understanding with Taggart Global USA, LLC. The cost for the facility, located in eastern Kentucky, was $8.9 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.
 
Coal Processing and Transportation Fees.  Coal 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 coal 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 coal processing leases are structured in a manner 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


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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 and Depletion.  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 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. Timberlands are stated at cost less depletion. We determine the cost of the timber harvested based on the volume of timber harvested in relation to the amount of estimated net merchantable volume by geographic areas. We estimate our timber inventory using statistical information and data obtained from physical measurements and other information gathering techniques. We update these estimates annually, which may result in adjustments of timber volumes and depletion rates that we recognize prospectively. Changes in these estimates have no effect on our cash flow.
 
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 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 January 2010, the FASB amended fair value disclosure requirements. This amendment requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, see Note 9. “Fair Value Measurements” for the definition of Level 1 and Level 2 measurements. The amendment also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs. This amendment is effective for fiscal years beginning after December 15, 2010 and interim periods within those fiscal years. We do not expect this amendment to have an impact on our financial position, results of operations or cash flows.
 
In June 2009, the FASB issued a new standard amending previous consolidation of variable interest entities guidance. This amended guidance requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it controlling financial interest in a variable interest entity. This amendment is effective for fiscal years beginning after November 15, 2009 and interim periods within those fiscal years. We do not expect this guidance to have a material impact on the financial statements.
 
In June 2009, the FASB issued a new standard that establishes the Codification as the source of authoritative U.S. accounting and reporting standards recognized by the FASB for use in the preparation of


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financial statements of nongovernmental entities that are presented in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities law are also sources of authoritative GAAP for SEC registrants. This standard is effective for interim and annual reporting periods after September 15, 2009. This standard had no impact on our financial position, results of operations or cash flows.
 
In May 2009, the FASB issued a subsequent events standard, which established general standards of accounting for and disclosure of events that occur subsequent to the balance sheet date but before financial statements are issued. This standard defines (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Under this standard, a public reporting entity shall evaluate subsequent events through the date the financial statements are issued. We adopted this standard for the quarter ended June 30, 2009. The adoption did not impact the financial position, results of operations or cash flows. As disclosed in Note 15. Subsequent Events, we evaluated events that have occurred subsequent to December 31, 2009 through the time of our filing on February 26, 2010.
 
On April 9, 2009, the FASB issued authoritative guidance that requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This authoritative guidance also requires those disclosures in summarized financial information at interim reporting periods. This authoritative guidance was effective for interim reporting periods ending after June 15, 2009, and requires that we provide fair value footnote disclosure related to our outstanding debt quarterly but will otherwise not materially impact the financial statements. Fair value measurements are disclosed in Note 9. “Fair Value Measurements”.
 
In June 2008, the FASB issued new authoritative guidance determining whether instruments granted in share-based payment transactions are participating securities. This authoritative guidance affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when the dividends do not need to be returned if the employees forfeit the award. This authoritative guidance requires that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders and are considered participating securities. Because the awards are considered participating securities, the issuing entity is required to apply the two-class method of computing basic and diluted earnings per share. The provisions of this authoritative guidance were effective for us on January 1, 2009, but because distributions accrued on our share-based payment awards are subject to forfeiture, the adoption did not impact earnings per unit.


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Results of Operations
 
Summary of 2009 and 2008 Royalties and Production
 
                                 
    For the Years Ended
             
    December 31,     Increase
    Percentage
 
    2009     2008     (Decrease)     Change  
    (In thousands, except percent and per ton data)  
 
Coal royalties
                               
Appalachia
                               
Northern
  $ 14,959     $ 17,074     $ (2,115 )     (12 )%
Central
    132,543       156,109       (23,566 )     (15 )%
Southern
    19,382       19,839       (457 )     (2 )%
                                 
Total Appalachia
    166,884       193,022       (26,138 )     (14 )%
Illinois Basin
    22,019       21,695       324       1 %
Northern Powder River Basin
    7,718       11,533       (3,815 )     (33 )%
                                 
Total
  $ 196,621     $ 226,250     $ (29,629 )     (13 )%
                                 
Production (tons)
                               
Appalachia
                               
Northern
    4,943       5,799       (856 )     (15 )%
Central
    28,032       35,967       (7,935 )     (22 )%
Southern
    3,233       4,273       (1,040 )     (24 )%
                                 
Total Appalachia
    36,208       46,039       (9,831 )     (21 )%
Illinois Basin
    6,656       8,313       (1,657 )     (20 )%
Northern Powder River Basin
    3,984       6,218       (2,234 )     (36 )%
                                 
Total
    46,848       60,570       (13,722 )     (23 )%
                                 
Average gross royalty revenue per ton
                               
Appalachia
                               
Northern
  $ 3.03     $ 2.94     $ .09       3 %
Central
    4.73       4.34       .39       9 %
Southern
    6.00       4.64       1.36       29 %
Total Appalachia
    4.61       4.19       .42       10 %
Illinois Basin
    3.31       2.61       .70       27 %
Northern Powder River Basin
    1.94       1.85       .09       5 %
Combined average gross royalty revenue per ton
  $ 4.20     $ 3.74     $ .46       12 %
Aggregates
                               
Royalty revenues
  $ 4,260     $ 6,275     $ (2,015 )     (32 )%
Aggregate Bonus Royalty
  $ 1,320     $ 2,844     $ (1,524 )     (54 )%
Production
    3,269       4,791       (1,522 )     (32 )%
Average gross royalty revenue per ton
  $ 1.30     $ 1.31     $ (.01 )     (1 )%


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Coal Royalty Revenues and Production
 
Coal royalty revenues comprised approximately 77% and 78% of our total revenue for the years ended December 31, 2009 and 2008, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
 
Appalachia.  Primarily as result of lower production on our property, coal royalty revenues decreased by $26.1 million in 2009. The decline 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, and some mines moving their production onto adjacent property. This reduction in production was partially offset by higher per ton royalties.
 
Illinois Basin.  Coal royalty revenues were nearly constant, being only $324,000 higher in 2009 than 2008, although production was 1.7 million tons lower. One mine finished producing on our property in 2009 and moved to adjacent properties. This loss in production was partially offset by production from our Williamson property, which is at a higher royalty rate per ton and therefore generated more coal royalty revenues. Production also began late in the year from our Macoupin property.
 
Northern Powder River Basin.  The decrease in both coal royalty revenues of $3.8 million and production of 2.2 million 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 located in Washington, Arizona, Texas and West Virginia. For the years ended December 31, 2009 and 2008, we recorded $5.6 million and $9.1 million, respectively, in royalty revenues from aggregates, and had production of 3.3 million tons and 4.8 million tons for each of these years. Nearly all of this production and revenue is attributable to the aggregate reserves in DuPont, Washington. In 2009 we received a bonus royalty payment of $1.3 million from the Washington reserves compared to a $2.8 million payment in 2008. The reduction in tonnage and royalty is primarily attributed to lower demand caused by the poorer economic conditions in 2009.


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Summary of 2008 and 2007 Royalties and Production
 
                                 
    For The Years Ended
             
    December 31,     Increase
    Percentage
 
    2008     2007     (Decrease)     Change  
    (In thousands, except percent and per ton data)  
 
Coal royalties
                               
Appalachia
                               
Northern
  $ 17,074     $ 16,664     $ 410       2 %
Central
    156,109       117,820       38,289       32 %
Southern
    19,839       17,832       2,007       11 %
                                 
Total Appalachia
    193,022       152,316       40,706       27 %
Illinois Basin
    21,695       7,963       13,732       172 %
Northern Powder River Basin
    11,533       11,064       469       4 %
                                 
Total
  $ 226,250     $ 171,343     $ 54,907       32 %
                                 
Production (tons)
                               
Appalachia
                               
Northern
    5,799       7,270       (1,471 )     (20 )%
Central
    35,967       35,835       132       <1 %
Southern
    4,273       4,603       (330 )     (7 )%
                                 
Total Appalachia
    46,039       47,708       (1,669 )     (3 )%
Illinois Basin
    8,313       3,709       4,604       124 %
Northern Powder River Basin
    6,218       5,815       403       7 %
                                 
Total
    60,570       57,232       3,338       6 %
                                 
Average gross royalty revenue per ton
                               
Appalachia
                               
Northern
  $ 2.94     $ 2.29     $ 0.65       28 %
Central
    4.34       3.29       1.05       32 %
Southern
    4.64       3.87       .77       20 %
Total Appalachia
    4.19       3.19       1.00       31 %
Illinois Basin
    2.61       2.15       .46       21 %
Northern Powder River Basin
    1.85       1.90       (.05 )     (3 )%
Combined average gross royalty revenue per ton
  $ 3.74     $ 2.99     $ .75       25 %
Aggregates
                               
Royalty revenues
  $ 6,275     $ 6,778     $ (503 )     (7 )%
Aggregate Bonus Royalty
  $ 2,844     $ 656     $ 2,188       334 %
Production
    4,791       5,698       (907 )     (16 )%
Average gross royalty revenue per ton
  $ 1.31     $ 1.19     $ 0.12       10 %
 
Coal Royalty Revenues and Production
 
Coal royalty revenues comprised approximately 78% and 80% of our total revenue for the years ended December 31, 2008 and 2007, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:


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Appalachia.  Primarily as result of higher coal prices, coal royalty revenues increased by $40.7 million in 2008, even though production was slightly lower than in 2007. The decline in production was primarily the result of a longwall mine in Northern Appalachia that had a substantial percentage of its production come from adjacent property.
 
Illinois Basin.  Coal royalty revenues were $13.7 million higher in 2008 and production was 4.6 million tons higher. As a result of a full year of operation at our Williamson property, coal royalty revenues attributable to that property were $15.8 million for the year ended December 31, 2008 compared to $2.6 million for 2007. Similarly, production attributable to that property was 5.5 million tons for 2008 compared to 1.0 million tons in 2007.
 
Northern Powder River Basin.  The increase in both coal royalty revenues of $0.5 million and production of 0.4 million 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
 
For the years ended December 31, 2008 and 2007, we recorded $6.3 million and $6.8 million, respectively in royalty revenues from aggregates, and had production of 4.8 million tons and 5.7 million tons for each of these years. Nearly all of this production and revenue is attributable to the aggregate reserves in DuPont, Washington. In 2008 we received a bonus royalty payment of $2.8 million compared to a $0.7 million payment in 2007.
 
Other Operating Results
 
Coal Processing and Transportation Revenues.  We generated $7.7 million, $8.8 million and $4.8 million in processing revenues for the years ended December 31, 2009, 2008 and 2007. We do not operate the preparation plants, but receive a fee for coal processed through them. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed through the facilities.
 
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 $12.5 million, $11.7 million and $4.0 million for the years ended December 31, 2009, 2008 and 2007, respectively. Production increased during the last half of 2008 and all of 2009 due to the longwall at our Williamson property coming online in March 2008.
 
Additional Revenues.  In addition to coal royalties, aggregate royalties, coal processing and transportation revenues, we generated approximately 13% of our revenues from other sources for the years ended December 31, 2009, 2008 and 2007. These other sources include: oil and gas royalties, property taxes, minimums recognized, overriding royalties, timber, rentals and wheelage.
 
Operating costs and expenses.  Included in total expenses are:
 
  •  Depreciation, depletion and amortization of $60.0 million, $64.3 million and $51.4 million for the years ended December 31, 2009, 2008 and 2007, respectively. Excluding a onetime expense of $8.2 million for a terminated lease due to a mine closure, depletion decreased from 2008 as a result of lower total production for 2009, while it remained approximately the same as 2007.
 
  •  General and administrative expenses of $23.1 million, $13.9 million and $20.0 million for the years ended December 31, 2009, 2008 and 2007, 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.
 
  •  Property, franchise and other taxes have increased for the year ended December 31, 2009 when compared to 2008 and 2007. This increase reflects higher West Virginia property taxes and Kentucky unmined mineral taxes. A substantial portion of our property taxes is reimbursed to us by our lessees and is reflected as property tax revenue on our statement of income.


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Interest Expense.  Interest expense was higher for the year ended December 31, 2009 when compared to the years ended December 31, 2008 and 2007 due to additional debt incurred to fund acquisitions and higher interest rates.
 
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 industry 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.
 
Our credit facility does not expire until 2012, and our credit ratios are within our debt covenants for both our credit facility and our outstanding senior notes. In addition, we are amortizing substantially all of our long-term debt 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 2009, 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. Following our second acquisition of reserves at the Deer Run mine and our final payment on the Blue Star reserve acquisition in January 2010, we had $229 million in available capacity under the facility. We also had approximately $83 million of cash available at the end of the year.
 
Net cash provided by operations for the years ended December 31, 2009, 2008 and 2007 was $210.7 million, $230.0 million and $168.2 million, respectively. A 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, 2009, 2008 and 2007 was $119.9 million, $9.8 million and $79.6 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. In 2007, we sold surface acreage in Wise County, Virginia for gross proceeds of $1.4 million.
 
Net cash used for financing activities for the years ended December 31, 2009, 2008 and 2007 was $98.1 million, $188.5 million and $96.2 million, respectively. We had proceeds from loans of $331.0 million and $285.4 million for the years ended December 31, 2009 and 2007. The proceeds were offset by repayment of credit facility borrowings of $151.0 million and $226.4 million for the years ended December 31, 2009 and 2007, respectively. We did not receive any proceeds from loans for the year ended December 31, 2008. We also made $17.2 million in principal payments on our senior notes for the years ended December 31, 2009 and 2008, respectively, and $9.5 million for the year ended December 31, 2007. Proceeds for the year ended December 31, 2009 were also offset by retirement of purchase obligations related to the purchase of reserves and infrastructure of $72.0 million. We paid distributions of $188.1 million, $171.3 million and $147.0 million for the years ended December 31, 2009, 2008 and 2007, respectively. We made $9.4 million in principal payments on our senior notes in 2007. In 2007, as a part of the Dingess-Rum and Mettiki acquisitions we received a $2.6 million cash contribution from our general partner to maintain its 2% interest.
 
Contractual Obligations and Commercial Commitments
 
Long-Term Debt
 
At December 31, 2009, our debt consisted of:
 
  •  $28.0 million of our $300 million floating rate revolving credit facility, due March 2012;
 
  •  $35.0 million of 5.55% senior notes due 2013;
 
  •  $43.7 million of 4.91% senior notes due 2018;
 
  •  $150.0 million of 8.38% senior notes due 2019;


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  •  $84.6 million of 5.05% senior notes due 2020;
 
  •  $2.3 million of 5.31% utility local improvement obligation due 2021;
 
  •  $40.2 million of 5.55% senior notes due 2023;
 
  •  $225.0 million of 5.82% senior notes due 2024; and
 
  •  $50.0 million of 8.92% senior notes due 2024.
 
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 5.82% senior notes due 2024 do not begin until March 2010, the scheduled principal payments on the 8.38% senior notes due 2019 do not begin until March 2013, and the scheduled principal payments on the 8.92% senior notes due 2024 do not begin until March 2014. We also make annual principal and interest payments on the utility local improvement obligation.
 
Credit Facility.  We have a $300 million revolving credit facility, and at December 31, 2009 we had approximately $272 million 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 $450 million on the same terms. However, under current market conditions, 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 attempt to bring new lenders into the facility, but we cannot make any assurance that any new lenders would elect to participate or that the excess credit capacity will be available to us at all or on the existing terms.
 
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 higher of the federal funds rate plus an applicable margin ranging from 0% to 0.50% or the prime rate as announced by the agent bank; or
 
  •  at a rate equal to LIBOR plus an applicable margin ranging from 0.45% to 1.50%.
 
We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.10% to 0.30% 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) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and
 
  •  a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters.
 
Senior Notes.  NRP Operating LLC issued the senior notes under a note purchase agreement. 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;
 
  •  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.


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In March 2009, we issued $150 million of 8.38% notes maturing March 25, 2019 and $50 million of 8.92% notes maturing March 2024. These senior notes provide that in the event that our 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.
 
The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2009 (in millions):
 
                                                         
    Payments Due by Period  
Contractual Obligations
  Total     2010     2011     2012     2013     2014     Thereafter  
 
Long-term debt (including current maturities)(1)
  $ 658.8     $ 32.2     $ 31.5     $ 58.8     $ 87.2     $ 56.2     $ 392.9  
Pending acquisitions(2)
    248.0       168.0       65.0       15.0                    
Rental lease(3)
    5.3       0.5       0.5       0.5       0.5       0.5       2.8  
                                                         
Total
  $ 912.1     $ 200.7     $ 97.0     $ 74.3     $ 87.7     $ 56.7     $ 395.7  
                                                         
 
 
(1) The amounts indicated in the table include principal and interest due on our senior notes, as well as the utility local improvement obligation related to our property in DuPont, Washington. The table includes the $28.0 million outstanding principal balance at December 31, 2009 under our credit facility, which matures in March 2012.
 
(2) The amounts indicated in the table include $245.0 million related to the future anticipated acquisitions with Colt LLC and $3.0 million due and paid in January 2010 to acquire aggregate reserves from Blue Star Materials, LLC. Future acquisitions from Colt LLC are based upon certain milestones relating to the new mine’s construction. Upon each closing we receive title to additional reserves. In January 2010 we funded the 2nd acquisition 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.
 
Two-for-One Limited Partner Unit Split
 
On April 18, 2007, we completed a two-for-one split of all of our limited partner units. Accordingly, all unit and per unit amounts reported reflect the split.
 
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, 2009, 2008 and 2007.
 
Environmental
 
The operations our lessees conduct on our properties are subject to federal and state environmental laws and regulations. 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


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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, 2009. 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 our 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. Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to unitholders. The reimbursements to our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $6.8 million in 2009, $5.6 million in 2008 and $5.0 million in 2007. 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 NRP’s general partner and in the incentive distribution rights of NRP, as well as 13,510,072 common units. At December 31, 2009, we had accounts receivable totaling $4.0 million from Cline affiliates. For the years ended December 31, 2009, 2008 and 2007, we had total revenue of $37.4 million, $27.9 million and $7.5 million, respectively, from these companies. In addition, we have received $16.2 million in advance minimum royalty payments that have not been recouped.
 
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, we 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. We currently have 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. We will own and lease the plants to Taggart Global, which will design, build and operate the plants. The lease payments are based on the sales price for the 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. For the years ended December 31, 2009, 2008 and 2007, we received total revenue of $3.9 million and $5.0 million and $2.7 million, respectively, from Taggart. At December 31, 2009, we had accounts receivable totaling $0.2 million from Taggart.


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In June 2007, a fund controlled by Quintana Capital acquired Kopper-Glo, a small coal mining company that is one of our lessees with operations in Tennessee. For the years ended December 31, 2009, 2008 and 2007, we had total revenue of $1.6 million and $1.4 million and $0.1 million, respectively, from Kopper-Glo, and at December 31, 2009, we had accounts receivable totaling $0.1 million from Kopper-Glo.
 
Office Building in Huntington, West Virginia
 
In 2008, Western Pocahontas Properties Limited Partnership completed construction of an office building in Huntington, West Virginia. On January 1, 2009, we began leasing substantially all of two floors of the building 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 80% 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 our current 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, 2009, we had $28 million outstanding in variable interest debt. If interest rates were to increase by 1%, annual interest expense would increase $280,000, assuming the same principal amount remained outstanding during the year.


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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, 2009 and 2008, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 10 to the consolidated financial statements, the consolidated financial statements have been retroactively adjusted to reflect the application of new accounting standard related to participating securities and earnings per unit.
 
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, 2009, 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 26, 2010 expressed an unqualified opinion thereon.
 
/s/  ERNST & YOUNG LLP
 
Houston, Texas
February 26, 2010


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NATURAL RESOURCE PARTNERS L.P.
 
 
                 
    December 31,
    December 31,
 
    2009     2008  
    (In thousands, except for unit information)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 82,634     $ 89,928  
Accounts receivable, net of allowance for doubtful accounts
    27,141       31,883  
Accounts receivable — affiliates
    4,342       1,351  
Other
    930       934  
                 
Total current assets
    115,047       124,096  
Land
    24,343       24,343  
Plant and equipment, net
    64,267       67,204  
Coal and other mineral rights, net
    1,151,313       979,692  
Intangible assets, net
    165,160       102,828  
Loan financing costs, net
    2,891       2,679  
Other assets, net
    569       498  
                 
Total assets
  $ 1,523,590     $ 1,301,340  
                 
 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 914     $ 861  
Accounts payable — affiliates
    179       365  
Obligation related to acquisition
    2,969        
Current portion of long-term debt
    32,235       17,235  
Accrued incentive plan expenses — current portion
    4,627       3,179  
Property, franchise and other taxes payable
    6,164       6,122  
Accrued interest
    10,300       6,419  
                 
Total current liabilities
    57,388       34,181  
Deferred revenue
    67,018       40,754  
Accrued incentive plan expenses
    7,371       4,242  
Long-term debt
    626,587       478,822  
Partners’ capital:
               
Common units outstanding: (69,451,136 in 2009, 64,891,136 in 2008)
    747,437       719,341  
General partner’s interest
    13,409       13,579  
Holders of incentive distribution rights
    4,977       11,069  
Accumulated other comprehensive loss
    (597 )     (648 )
                 
Total partners’ capital
    765,226       743,341  
                 
Total liabilities and partners’ capital
  $ 1,523,590     $ 1,301,340  
                 
 
The accompanying notes are an integral part of these financial statements.


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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME
 
                         
    For the Years Ended December 31,  
    2009     2008     2007  
    (In thousands, except per unit data)  
 
Revenues:
                       
Coal royalties
  $ 196,621     $ 226,250     $ 171,343  
Aggregate royalties
    5,580       9,119       7,434  
Coal processing fees
    7,673       8,781       4,824  
Transportation fees
    12,517       11,656       3,984  
Oil and gas royalties
    7,520       7,902       4,930  
Property taxes
    11,636       9,800       10,285  
Minimums recognized as revenue
    1,266       1,257       1,951  
Override royalties
    9,251       11,327       3,794  
Other
    4,020       5,573       6,440  
                         
Total revenues
    256,084       291,665       214,985  
Operating costs and expenses:
                       
Depreciation, depletion and amortization
    60,012       64,254       51,391  
General and administrative
    23,102       13,922       20,048  
Property, franchise and other taxes
    14,996       13,558       13,613  
Transportation costs
    1,611       1,416       298  
Coal royalty and override payments
    2,388       1,508       1,336  
                         
Total operating costs and expenses
    102,109       94,658       86,686  
                         
Income from operations
    153,975       197,007       128,299  
Other income (expense)
                       
Interest expense
    (40,108 )     (28,356 )     (28,690 )
Interest income
    213       1,355       2,890  
                         
Net income
  $ 114,080     $ 170,006     $ 102,499  
                         
Net income attributable to:
                       
General partner
  $ 1,611     $ 2,602     $ 1,489  
                         
Holders of incentive distribution rights
  $ 33,515     $ 39,914     $ 28,079  
                         
Limited partners
  $ 78,954     $ 127,490     $ 72,931  
                         
Basic and diluted net income per limited partner unit
  $ 1.17     $ 1.95     $ 1.11  
                         
Weighted average number of units outstanding
    67,702       64,891       64,505  
                         
 
The accompanying notes are an integral part of these financial statements.


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NATURAL RESOURCE PARTNERS L.P.

STATEMENT OF PARTNERS’ CAPITAL
 
                                                 
                      Holders
             
                      of Incentive
    Accumulated
       
                General
    Distribution
    Other
       
    Common Units     Partner
    Rights
    Comprehensive
       
    Units     Amounts     Amounts     Amounts     Income (Loss)     Total  
    (In thousands, except unit data)  
 
Balance at December 31, 2006
    50,681,064     $ 422,536     $ 8,791     $ 5,111     $ (751 )   $ 435,687  
Issuance of units for acquisitions
    14,210,072       346,319       4,422                   350,741  
Capital contribution
                2,645                   2,645  
Distributions to unitholders
          (118,855 )     (2,942 )     (25,236 )           (147,033 )
Net income for the year ended
                                               
December 31, 2007
          72,931       1,489       28,079             102,499  
Loss on interest hedge
                            52       52  
                                                 
Comprehensive income
                            52       102,551  
                                                 
Balance at December 31, 2007
    64,891,136     $ 722,931     $ 14,405       7,954     $ (699 )   $ 744,591  
                                                 
Distributions to unitholders
          (131,080 )     (3,428 )     (36,799 )           (171,307 )
Net income for the year ended
                                               
December 31, 2008
          127,490       2,602       39,914             170,006  
Loss on interest hedge
                            51       51  
                                                 
Comprehensive income
                            51       170,057  
                                                 
Balance at December 31, 2008
    64,891,136     $ 719,341     $ 13,579     $ 11,069     $ (648 )   $ 743,341  
                                                 
Distributions to unitholders
          (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  
                                                 
 
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
 
                         
    For the Years Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income
  $ 114,080     $ 170,006     $ 102,499  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    60,012       64,254       51,391  
Non-cash interest charge
    1,463       278       443  
Gain(loss) on sale of assets
          33       (1,236 )
Change in operating assets and liabilities:
                       
Accounts receivable
    581       (4,586 )     (5,270 )
Other assets
    (67 )     178       178  
Accounts payable and accrued liabilities
    (133 )     (1,484 )     (464 )
Accrued interest
    3,850       143       2,430  
Deferred revenue
    26,264       4,468       15,632  
Accrued incentive plan expenses
    4,577       (3,041 )     465  
Property, franchise and other taxes payable
    42       (293 )     2,085  
                         
Net cash provided by operating activities
    210,669       229,956       168,153  
                         
Cash flows from investing activities:
                       
Acquisition of land, coal, other mineral rights and related intangibles
    (118,754 )     (5,500 )     (58,124 )
Acquisition or construction of plant and equipment
    (1,157 )     (10,568 )     (16,695 )
Proceeds from sale of assets
                1,425  
Change in restricted accounts
          6,240       (6,240 )
                         
Net cash used in investing activities
    (119,911 )     (9,828 )     (79,634 )
                         
Cash flows from financing activities:
                       
Proceeds from loans
    331,000             285,400  
Deferred financing costs
    (661 )           (1,292 )
Repayments of loans
    (168,235 )     (17,234 )     (235,942 )
Retirement of purchase obligation related to reserves and infrastructure
    (72,000 )            
Costs associated with unit issuance
    (21 )            
Distributions to partners
    (188,135 )     (171,307 )     (147,033 )
Contributions by general partner
                2,645  
                         
Net cash used in financing activities
    (98,052 )     (188,541 )     (96,222 )
                         
Net increase (decrease) in cash and cash equivalents
    (7,294 )     31,587       (7,703 )
Cash and cash equivalents at beginning of period
    89,928       58,341       66,044  
                         
Cash and cash equivalents at end of period
  $ 82,634     $ 89,928     $ 58,341  
                         
Supplemental cash flow information:
                       
Cash paid during the period for interest
  $ 34,710     $ 27,735     $ 25,771  
                         
Non-cash investing activities:
                       
Equity issued for acquisitions
  $ 95,910     $     $ 346,319  
Assets contributed by general partner for acquisitions
    1,981             4,422  
Liability assumed from acquisitions
    1,170             1,989  
Purchase obligation related to reserve and infrastructure acquisition
    74,022              
 
The accompanying notes are an integral part of these financial statements.


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NATURAL RESOURCE PARTNERS L.P.
 
 
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 coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2009, the Partnership owned or controlled approximately 2.1 billion tons of proven and probable coal reserves (unaudited). The Partnership does not operate any mines, but leases coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine coal 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 of coal sold, in addition to a minimum payment.
 
In addition, the Partnership owns coal transportation and preparation equipment, aggregate reserves, 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. 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. For additional discussion concerning the Partnership’s valuation of intangible assets, see Note 7, “Intangible Assets.”
 
Fair Value Measurements
 
The Partnership accounts for fair value measurements, including disclosures, using Financial Accounting Standard Board’s (FASB) fair value standard. For additional discussion concerning the Partnership’s fair value measurement, see Note 9, “Fair Value Measurement”.
 
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. Restricted cash includes deposits to secure performance under contracts acquired as part of the Cline acquisition. Earnings on the restricted cash are available to the Partnership. Performance under the Cline contracts was completed in November 2008 and the funds were released from escrow at that time.
 
Accounts Receivable
 
Accounts receivable are recorded on the basis of tons of minerals sold by the Partnership’s lessees in the ordinary course of business, and do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying consolidated balance sheets. The Partnership evaluates the collectibility 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 coal 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 contractual rights.
 
Plant and Equipment
 
Plant and equipment consists of coal preparation plants, related coal handling facilities, and other coal 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.
 
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. During 2009, included in depletion is a onetime charge of $8.2 million related to a terminated lease from a mine closure.
 
Concentration of Credit Risk
 
Substantially all of the Partnership’s accounts receivable result from amounts due from third-party companies in the coal industry, with approximately 65% of our total revenues being attributable to coal royalty revenues from Appalachia. This concentration of customers may impact the Partnership’s overall credit risk,


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
either positively or negatively, in that these entities may be affected by changes in economic or other conditions. Receivables are generally not collateralized.
 
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.
 
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, subject to minimum annual or quarterly payments.
 
Coal Processing and Transportation Fees.  Coal 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 coal 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 coal that is processed and sold from the facilities. The coal processing leases are structured in a manner 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, the Partnership receives 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 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 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.
 
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 revenues in the statement of income as property taxes.
 
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 and the taxable income allocation requirements under its partnership agreement. 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 under 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


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
New Accounting Standards
 
In January 2010, the FASB amended fair value disclosure requirements. This amendment requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, see Note 9. “Fair Value Measurements” for the definition of Level 1 and Level 2 measurements. The amendment also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs. This amendment is effective for fiscal years beginning after December 15, 2010 and interim periods within those fiscal years. The Partnership does not expect this amendment to have an impact on the Partnership’s financial position, results of operations or cash flows.
 
In June 2009, the FASB issued a new standard amending previous consolidation of variable interest entities guidance. This amended guidance requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it controlling financial interest in a variable interest entity. This amendment is effective for fiscal years beginning after November 15, 2009 and interim periods within those fiscal years. The Partnership does not expect this adoption to have a material impact on the financial statements.
 
In June 2009, the FASB issued a new standard that establishes the Codification as the source of authoritative U.S. accounting and reporting standards recognized by the FASB for use in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities law are also sources of authoritative GAAP for SEC registrants. This standard is effective for interim and annual reporting periods after September 15, 2009. This standard had no impact on the Partnership’s financial position, results of operations or cash flows.
 
In May 2009, the FASB issued a subsequent events standard, which established general standards of accounting for and disclosure of events that occur subsequent to the balance sheet date but before financial statements are issued. This standard defines (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Under this standard, a public reporting entity shall evaluate subsequent events through the date the financial statements are issued. The Partnership adopted this standard for the quarter ended June 30, 2009. The adoption did not impact the financial position, results of operations or cash flows. As disclosed in Note 15. Subsequent Events, the Partnership evaluated events that have occurred subsequent to December 31, 2009 through the time of the Partnership’s filing on February 26, 2010.
 
On April 9, 2009, the FASB issued authoritative guidance that requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This authoritative guidance also requires those disclosures in summarized financial information at interim reporting periods. This authoritative guidance was effective for interim reporting periods ending after June 15, 2009, and requires that the Partnership provide fair value footnote disclosure related to its outstanding debt quarterly but will otherwise not materially impact the financial statements. Fair value measurements are disclosed in Note 9, “Fair Value Measurements.”
 
In June 2008, the FASB issued new authoritative guidance determining whether instruments granted in share-based payment transactions are participating securities. This authoritative guidance affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when the dividends do not need to be returned if the employees forfeit the award. This authoritative guidance requires that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders and are considered participating securities. Because the


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
awards are considered participating securities, the issuing entity is required to apply the two-class method of computing basic and diluted earnings per share. The provisions of this authoritative guidance were effective for the Partnership on January 1, 2009, but because distributions accrued on the Partnership’s share-based payment awards are subject to forfeiture, the adoption did not impact earnings per unit.
 
In December 2007, the FASB issued a new business combination standard that establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any controlling interest; recognizes and measures goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The Partnership adopted this standard on January 1, 2009 and, therefore, acquisitions accounted for as business combinations that are completed by the Partnership will be impacted by this new standard.
 
In December 2007, the FASB issued a new standard that establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This authoritative guidance was effective for the Partnership on January 1, 2009. The adoption did not impact the financial statements.
 
In September 2006, the FASB issued a new fair value standard, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This standard eliminates inconsistencies found in various prior pronouncements but does not require any new fair value measurements. This standard was effective for the Partnership on January 1, 2008, but in February 2008, the FASB, permitted entities to delay application of this new standard to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). On January 1, 2009, the Partnership began applying the new fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis.
 
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.   Acquisitions
 
AzConAgg.  In December 2009, the Partnership acquired approximately 230 acres of mineral and surface rights related to sand and gravel reserves in southern Arizona from a local operator for $3.75 million.
 
Colt.  In September 2009, the Partnership signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt LLC, an affiliate of the Cline Group, through eight separate transactions for a total purchase price of $255 million. Upon closing of the first transaction, the Partnership paid $10.0 million, funded through the Partnership’s credit facility, and acquired approximately 3.3 million tons of reserves associated with the initial production from the mine. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.
 
Blue Star.  In July 2009, the Partnership acquired approximately 121 acres of limestone reserves in Wise County, Texas from Blue Star Materials, LLC for a purchase price of $24 million. As of December 31, 2009, the Partnership had funded $21.0 million of the acquisition with cash and borrowings under the Partnership’s credit facility.
 
Gatling Ohio.  In May 2009, the Partnership completed the purchase of the membership interests in two companies from Adena Minerals, LLC, an affiliate of the Cline Group. The companies own 51.5 million tons of coal reserves and infrastructure assets at Cline’s Yellowbush Mine located on the Ohio River in Meigs County, Ohio. The Partnership issued 4,560,000 common units to Adena Minerals in connection with this


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
acquisition. In addition, the general partner of Natural Resource Partners granted Adena Minerals an additional nine percent interest in the general partner as well as additional incentive distribution rights.
 
Massey- Jewell Smokeless.  In March 2009, the Partnership acquired from Lauren Land Company, a subsidiary of Massey Energy, the remaining four-fifths interest in coal reserves located in Buchanan County, Virginia in which the Partnership previously held a one-fifth interest. Total consideration for this purchase was $12.5 million.
 
Macoupin.  In January 2009, the Partnership acquired approximately 82 million tons of coal reserves and infrastructure assets related to the Shay No. 1 mine in Macoupin County, Illinois for $143.7 million from Macoupin Energy, LLC, an affiliate of the Cline Group.
 
Coal Properties.  In October 2008, the Partnership acquired an overriding royalty for $5.5 million from Coal Properties Inc. This overriding royalty agreement is for coal reserves located in the states of Illinois and Kentucky.
 
Mid-Vol Coal Preparation Plant.  In April 2008, the Partnership completed construction of a coal preparation plant and coal handling infrastructure under the Partnership’s memorandum of understanding with Taggart Global USA, LLC. The total cost to build the facilities was $12.7 million.
 
Licking River Preparation Plant.  In March 2008, the Partnership signed an agreement for the construction of a coal preparation plant facility under the Partnership’s memorandum of understanding with Taggart Global USA, LLC. The total cost for the facility, located in eastern Kentucky, was $8.9 million.
 
4.   Allowance for Doubtful Accounts
 
Activity in the allowance for doubtful accounts for the years ended December 31, 2009, 2008 and 2007 was as follows:
 
                         
    2009     2008     2007  
    (In thousands)  
 
Balance, January 1
  $ 366     $ 1,272     $ 906  
Provision charged to operations:
                       
Additions to the reserve
    37       366       871  
Collections of previously reserved accounts
    (31 )     (1,037 )     (505 )
                         
Total charged (credited) to operations
    6       (671 )     366  
Non-recoverable balances written off
          (235 )      
                         
Balance, December 31
  $ 372     $ 366     $ 1,272  
                         
 
5.   Plant and Equipment
 
The Partnership’s plant and equipment consist of the following:
 
                 
    December 31,
    December 31,
 
    2009     2008  
    (In thousands)  
 
Plant construction in process
  $     $ 8,524  
Plant and equipment at cost
    81,782       68,197  
Less accumulated depreciation
    (17,515 )     (9,517 )
                 
Net book value
  $ 64,267     $ 67,204  
                 
 


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    For the Years Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Total depreciation expense on plant and equipment
  $ 7,998     $ 4,965     $ 3,904  
                         
 
6.   Coal and Other Mineral Rights
 
The Partnership’s coal and other mineral rights consist of the following:
 
                 
    December 31,
    December 31,
 
    2009     2008  
    (In thousands)  
 
Coal and other mineral rights
  $ 1,460,462     $ 1,253,314  
Less accumulated depletion and amortization
    (309,149 )     (273,622 )
                 
Net book value
  $ 1,151,313     $ 979,692  
                 
 
                         
    For the Years Ended
    December 31,
    2009   2008   2007
    (In thousands)
 
Total depletion and amortization expense on coal and other mineral interests
  $ 48,591     $ 55,896     $ 45,519  
                         
 
Included in depletion in 2009 is a onetime charge of $8.2 million related to a terminated lease from a mine closure.
 
7.   Intangible Assets
 
In 2009, the Partnership identified $65.8 million of above market contracts relating to the Gatling Ohio and Macoupin acquisitions . Amounts recorded as intangible assets along with the balances and accumulated amortization at December 31, 2009 and 2008 are reflected in the table below:
 
                 
    December 31,
    December 31,
 
    2009     2008  
    (In thousands)  
 
Above market contracts
  $ 173,312     $ 107,557  
Less accumulated amortization
    (8,152 )     (4,729 )
                 
Net book value
  $ 165,160     $ 102,828  
                 
 
                         
    For the Years Ended December 31,
    2009   2008   2007
    (In thousands)
 
Total amortization expense on intangible assets
  $ 3,423     $ 3,394     $ 1,335  
                         
 
Amortization expense is based upon the production and sales of coal from acquired reserves and the number of tons of coal transported using the transportation infrastructure. The estimates of 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.
 

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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
         
Estimated amortization expense (In thousands)
       
For year ended December 31, 2010
  $ 4,664  
For year ended December 31, 2011
    5,330  
For year ended December 31, 2012
    5,098  
For year ended December 31, 2013
    5,098  
For year ended December 31, 2014
    5,098  
 
8.   Long-Term Debt
 
Long-term debt consists of the following:
 
                 
    December 31,
    December 31,
 
    2009     2008  
    (In thousands)  
 
$300 million floating rate revolving credit facility, due March 2012
  $ 28,000     $ 48,000  
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
    43,700       49,750  
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        
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020
    84,615       92,308  
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021
    2,307       2,499  
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023
    40,200       43,500  
5.82% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2010, maturing in March 2024
    225,000       225,000  
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        
                 
Total debt
    658,822       496,057  
Less — current portion of long term debt
    (32,235 )     (17,235 )
                 
Long-term debt
  $ 626,587     $ 478,822  
                 
 
Principal payments due in:
 
         
2010
  $ 32,235  
2011
    31,518  
2012
    58,801  
2013
    87,230  
2014
    56,175  
Thereafter
    392,863  
         
    $ 658,822  
         

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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
In March 2009, the Partnership completed a private placement of $200 million of senior unsecured notes. Two tranches of amortizing senior notes were issued: $150 million that bear interest at 8.38%; and $50 million that bear interest at 8.92%. Both tranches of the notes have semi-annual interest payments. These 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.
 
The Partnership made principal payments of $17.2 million for the years ended December 31, 2009 and 2008.
 
The Partnership has a $300 million revolving credit facility, and at December 31, 2009, $272 million was available under the facility. The Partnership incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.10% to 0.30% per annum. Under an accordion feature in the credit facility, the Partnership may request its lenders to increase their aggregate commitment to a maximum of $450 million on the same terms.
 
The Partnership had $28.0 million and $48.0 million outstanding on its revolving credit facility at December 31, 2009 and 2008, respectively. The weighted average interest rate at December 31, 2009 and 2008 was 2.07% and 5.14%, respectively. Interest capitalized as part of the construction cost of Plant and Equipment was $0.2 million in 2008.
 
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) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and
 
  •  a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 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, 2009.
 
9.   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


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
  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 financial instruments included in 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 $627.5 million and $385.5 million at December 31, 2009 and 2008, respectively, for the senior notes. The carrying value of the Partnership’s long-term debt was $658.8 million and $496.1 million at December 31, 2009 and 2008, respectively, for the senior notes. 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.
 
10.   Net Income Per Unit Attributable to Limited Partners and Adoption of Two-Class Method
 
The Partnership adopted FASB’s authoritative guidance for master limited partnerships relating to the application of the two-class method for earnings per unit that was effective January 1, 2009. This guidance provides direction related to the calculation of earnings per unit for master limited partnerships that have Incentive Distribution Rights (IDRs) as part of their equity structure. Under the Partnership Agreement, IDRs are a separate interest from that of the General Partner and therefore are a participating security. However, IDRs participate in income only to the extent of cash distributions and such distributions as required in the Partnership Agreement are considered priority distributions. Therefore distributions on the IDRs from income for the current period are subtracted from net income prior to the determination of net income allocable to limited and general partnership interests. Net income per limited partnership unit is determined based on cash distributions to those interests from income of the period increased for their share of any undistributed earnings or reduced for their share of distributions in excess of earnings for the period. As provided for in the Partnership Agreement, IDRs do not have an interest in undistributed earnings and do not share in losses of the Partnership. As required by the guidance, all prior periods have been restated to conform to the new guidance including presentation of the equity interests of IDRs as a separate component of equity. In prior periods, the IDRs owned by the General Partner were included in the equity interest of the General Partner. As the IDRs of the Partnership are not denominated in terms of shares or units, earnings for those interests on a per unit or share basis are not presented separately in the accompanying financial statements. Basic and diluted net income per unit attributable to limited partners are the same since the Partnership has no potentially dilutive securities outstanding.
 
In connection with an acquisition, the holders of the IDRs elected to cap the distribution at Tier III for the quarters ending September 30, 2009 and December 31, 2009. The increase in basic and diluted net income per limited partner unit due to the forgone distributions for the year ended December 31, 2009 was $0.21 per unit.
 
11.   Related Party Transactions
 
Reimbursements to Affiliates of our General Partner
 
The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $6.8 million, $5.6 million and $5.0 million for the years ended December 31, 2009, 2008 and 2007, respectively. At December 31, 2009 and 2008, the Partnership also had accounts payable to affiliates of $0.2 million and $0.4 million, respectively.
 
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 and in the incentive distribution rights of the Partnership, as well as 13,510,072 common units. At December 31, 2009 and 2008, the Partnership had accounts receivable totaling $4.0 million and $1.6 million from Cline affiliates, respectively. For the years ended December 31, 2009, 2008 and 2007, the Partnership had total revenue of $37.4 million, $27.9 million and $7.5 million, respectively, from these companies. In addition, the Partnership has also received $16.2 million in advance minimum royalty payments that have not been recouped.
 
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. For the years ended December 31, 2009, 2008 and 2007, the Partnership received total revenue of $3.9 million, $5.0 million and $2.7 million, respectively, from Taggart. At December 31, 2009 and 2008, the Partnership had accounts receivable totaling $0.2 million and $0.4 million from Taggart, respectively.
 
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. For the years ended December 31, 2009, 2008 and 2007, the Partnership had total revenue of $1.6 million, $1.4 million and $0.1 million, respectively, from Kopper-Glo, and at December 31, 2009 and 2008, the Partnership had accounts receivable totaling $0.1 million and $0.2 million from Kopper-Glo, respectively.
 
Office Building in Huntington, West Virginia
 
In 2008, Western Pocahontas Properties completed construction of an office building in Huntington, West Virginia. On January 1, 2009, the Partnership began leasing substantially all of two floors of the building from Western Pocahontas Properties and pays $0.5 million in lease payments each year through December 31, 2018.
 
12.   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.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Acquisition
 
In conjunction with a definitive agreement, the Partnership may be obligated to purchase in excess of 190 million additional tons of coal reserves from Colt, LLC for an aggregate purchase price of $245 million over the next two years as certain milestones are completed related to construction of a new mine.
 
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 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, 2009. The Partnership is not associated with any environmental contamination that may require remediation costs.
 
Lease
 
On January 1, 2009, the Partnership leased it office facilities in Huntington, WV under a lease that requires annual payments of $0.5 million for each year through December 31, 2018.
 
13.   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, 2009, 2008 and 2007. Revenues from that lessee are as follows:
 
                                                 
    For the Years Ended December 31,  
    2009     2008     2007  
    Revenues     Percent     Revenues     Percent     Revenues     Percent  
    (Dollars in thousands)  
 
Alpha Natural Resources
  $ 28,941       11.3 %   $ 37,400       12.8 %   $ 26,481       12.3 %
The Cline Group
  $ 37,368       14.6 %   $ 27,938       9.6 %   $ 7,525       3.5 %
 
14.   Incentive Plans
 
GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.
 
Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
A summary of activity in the outstanding grants for the year ended December 31, 2009 are as follows:
 
         
Outstanding grants at the beginning of the period
    571,284  
Grants during the period
    207,366  
Grants vested and paid during the period
    (125,052 )
Forfeitures during the period
     
         
Outstanding grants at the end of the period
    653,598  
         
 
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability fluctuates with the market value of the Partnership units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and historical volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.65% to 1.57% and 44.17% to 57.65%, respectively at December 31, 2009. The Partnership’s historical dividend rate of 6.55% was used in the calculation at December 31, 2009. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $10.6 million and $6.1 million for the years ended December 31, 2009 and 2007, respectively. During 2008, the Partnership reversed accruals of approximately $0.3 million due to the decrease in unit price from December 31, 2007 to December 31, 2008. In connection with the Long-Term Incentive Plans, cash payments of $2.9 million, $3.2 million and $5.8 million were paid during each of the years ended December 31, 2009, 2008, and 2007, respectively. The grant date fair value was $31.01, $36.22 and $34.64 per unit for awards in 2009, 2008 and 2007, respectively and the unaccrued cost associated with the unvested outstanding grants at December 31, 2009 was $8.2 million.
 
In connection with the phantom unit awards granted in February 2008 and 2009, the CNG Committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units. The DERs have a four-year vesting period, and the Partnership accrues the cost of the distributions over that period. The expense associated with the DERs is included in the LTIP accrual for each year.
 
15.   Subsequent Events (Unaudited)
 
The following represents material events that have occurred subsequent to December 31, 2009 through the time of the Partnership’s filing on February 26, 2010, the date the Partnership’s Form 10-K was filed with the Securities and Exchange Commission:
 
Acquisitions
 
On January 11, 2010, the Partnership closed the second transaction with Colt LLC, an affiliate of the Cline Group. The Partnership paid $40.0 million, funded through its credit facility, and acquired approximately 19.5 million tons of reserves.
 
On January 15, 2010, the Partnership paid the final $3.0 million of the total of $24.0 million for the acquisition of limestone reserves from Blue Star Materials, LLC, which was funded through its credit facility.
 
Distributions
 
On February 12, 2010, the Partnership paid a quarterly distribution of $0.54 per unit to all holders of common units.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
16.   Supplemental Financial Data (Unaudited)
 
Selected Quarterly Financial Information
(In thousands, except per unit data)
 
                                 
    First
    Second
    Third
    Fourth
 
2009
  Quarter     Quarter     Quarter     Quarter  
 
Total revenues
  $ 66,733     $ 59,487     $ 63,962     $ 65,902  
Income from operations
  $ 41,417     $ 27,661     $ 41,395     $ 43,502  
Net income
  $ 33,420     $ 17,082     $ 30,651     $ 32,927  
Basic and diluted net income per limited partner unit
  $ 0.33     $ 0.07     $ 0.36     $ 0.39  
Weighted average number of units outstanding:
                               
Common
    64,891       66,946       69,451       69,451  
 
                                 
    First
    Second
    Third
    Fourth
 
2008
  Quarter     Quarter     Quarter     Quarter  
 
Total revenues
  $ 64,055     $ 75,592     $ 76,196     $ 75,822  
Income from operations
  $ 40,768     $ 47,105     $ 53,882     $ 55,252  
Net income
  $ 33,852     $ 40,353     $ 47,338     $ 48,463  
Basic and diluted net income per limited partner unit(1)
  $ 0.38     $ 0.46     $ 0.55     $ 0.56  
Weighted average number of units outstanding:
                               
Common
    64,891       64,891       64,891       64,891  
 
 
(1) Basic and diluted net income per limited partner unit has been restated for the adoption of the two-class method for earning per unit. See Note 10, “Net Income Per Unit Attributable to Limited Partners and Adoption of Two-Class Method.”


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Item 9.   Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
 
None.
 
Item 9A.   Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act) as of December 31, 2009. This evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective in producing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosures.
 
Management’s Report on Internal Control Over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2009. No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s consolidated financial statements included in this Form 10-K, has issued a report on the Partnership’s internal control over financial reporting, which is included herein.
 
Report of Independent Registered Public Accounting Firm
 
The Partners of Natural Resource Partners L.P.
 
We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Natural Resource Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial


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statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2009 and 2008, and the related consolidated statements of income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2009 of Natural Resource Partners L.P. and our report dated February 26, 2010 expressed an unqualified opinion thereon.
 
/s/  Ernst & Young LLP
 
Houston, Texas
February 26, 2010
 
Item 9B.   Other Information
 
None.


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PART III
 
Item 10.   Directors and Executive Officers of the Managing General Partner and Corporate Governance
 
As a master limited partnership we do not employ any of the people responsible for the management of our properties. Instead, we reimburse affiliates of our managing general partner, GP Natural Resource Partners LLC, for their services. The following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC. Each officer and director is elected for their respective office or directorship on an annual basis. Unless otherwise noted below, the individuals served as officers or directors of the partnership since the initial public offering. Subject to the Investor Rights Agreement with Adena Minerals, LLC, Mr. Robertson is entitled to nominate 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.
 
             
Name
 
Age
 
Position with the General Partner
 
Corbin J. Robertson, Jr. 
    62     Chairman of the Board and Chief Executive Officer
Nick Carter
    63     President and Chief Operating Officer
Dwight L. Dunlap
    56     Chief Financial Officer and Treasurer
Kevin F. Wall
    53     Executive Vice President — Operations
Wyatt L. Hogan
    37     Vice President, General Counsel and Secretary
Dennis F. Coker
    42     Vice President, Aggregates
Kevin J. Craig
    41     Vice President, Business Development
Kenneth Hudson
    55     Controller
Kathy H. Roberts
    58     Vice President, Investor Relations
Robert T. Blakely
    68     Director
David M. Carmichael
    71     Director
J. Matthew Fifield
    36     Director
Robert B. Karn III
    68     Director
S. Reed Morian
    64     Director
W. W. Scott, Jr. 
    65     Director
Stephen P. Smith
    48     Director
Leo A. Vecellio, Jr. 
    63     Director
 
Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC since 2002. Mr. Robertson has vast business experience having founded and served as a director and as an officer of multiple companies, both private and public, and has served on the boards of numerous non-profit organizations. He has served as the Chief Executive Officer and Chairman of the Board of the general partners of Western Pocahontas Properties Limited Partnership since 1986, Great Northern Properties Limited Partnership since 1992, Quintana Minerals Corporation since 1978, and as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986. He also serves as a Principal with Quintana Capital Group, Chairman of the Board of the Cullen Trust for Higher Education and on the boards of the American Petroleum Institute, the National Petroleum Council, the Baylor College of Medicine and the World Health and Golf Association. In 2006, Mr. Robertson was inducted into the Texas Business Hall of Fame.
 
Nick Carter has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since 2002. He has also served as President of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation since 1990 and as President of the general partner of Great Northern Properties Limited Partnership from 1992 to 1998. Prior to 1990, Mr. Carter held various positions with MAPCO Coal Corporation and was engaged in the private practice of law. He is Chairman of the National Council of Coal Lessors, a past Chair of the West Virginia Chamber of Commerce and a board member of the Kentucky Coal Association, West Virginia Coal Association, Indiana Coal Council, Community Trust Bancorp, Inc., Vigo Coal Company, Inc. and Carbo*Prill, Inc.


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Dwight L. Dunlap has served as the Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC since 2002. Mr. Dunlap has served as Vice President and Treasurer of Quintana Minerals Corporation and as Chief Financial Officer, Treasurer and Assistant Secretary of the general partner of Western Pocahontas Properties Limited Partnership, Chief Financial Officer and Treasurer of Great Northern Properties Limited Partnership and Chief Financial Officer, Treasurer and Secretary of New Gauley Coal Corporation since 2000. Mr. Dunlap has worked for Quintana Minerals since 1982 and has served as Vice President and Treasurer since 1987. Mr. Dunlap is a Certified Public Accountant with over 30 years of experience in financial management, accounting and reporting including six years of audit experience with an international public accounting firm.
 
Kevin F. Wall has served as Executive Vice President — Operations of GP Natural Resource Partners LLC since 2008. Mr. Wall was promoted to Executive Vice President — Operations in December 2008. Prior to then he served as Vice President — Engineering for GP Natural Resource Partners LLC from 2002-2008, the general partner of Western Pocahontas Properties Limited Partnership since 1998 and the general partner of Great Northern Properties Limited Partnership since 1992. He has also served as the Vice President — Engineering of New Gauley Coal Corporation since 1998. He has performed duties in the land management, planning, project evaluation, acquisition and engineering areas since 1981. He is a Registered Professional Engineer in West Virginia and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers and of the National Society of Professional Engineers. Mr. Wall also serves on the Board of Directors of Leadership Tri-State as well as the Board of the Virginia Center for Coal and Energy Research and is a past president of the West Virginia Society of Professional Engineers.
 
Wyatt L. Hogan has served as Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC since 2003. Mr. Hogan joined NRP in May 2003 from Vinson & Elkins L.L.P., where he practiced corporate and securities law from August 2000 through April 2003. He has also served since 2003 as the Vice President, General Counsel and Secretary of Quintana Minerals Corporation, the Secretary for the general partner of Western Pocahontas Properties Limited Partnership and as General Counsel and Secretary for the general partner of Great Northern Properties Limited Partnership. He is also member of the Board of Directors of Quintana Minerals Corporation. Prior to joining Vinson & Elkins in August 2000, he practiced corporate and securities law at Andrews & Kurth L.L.P. from September 1997 through July 2000.
 
Dennis F. Coker is Vice President, Aggregates of GP Natural Resource Partners LLC. Mr. Coker joined NRP in March 2008 from Hanson Building Materials America, where he had been employed since 2002, and most recently served as Director, Corporate Development. Mr. Coker has 14 years of experience in the aggregate industry, with the last nine years focused on business development activity. He formerly served as Chairman of the Young Leaders Council of the National Stone Sand and Gravel Association.
 
Kevin J. Craig is the Vice President of Business Development for GP Natural Resource Partners LLC. Mr. Craig joined NRP in 2005 from CSX Transportation, where he served as Terminal Manager for the West Virginia Coalfields. He has extensive marketing and finance experience with CSX since 1996. Mr. Craig also serves as a Delegate to the West Virginia House of Delegates having been elected in 2000 and re-elected in 2002, 2004, 2006 and 2008. Mr. Craig currently serves as Vice Chairman of the Committee on Economic Development. Prior to joining CSX, he served as a Captain in the United States Army.
 
Kenneth Hudson has served as the Controller of GP Natural Resource Partners LLC since 2002. He has served as Controller of the general partner of Western Pocahontas Properties Limited Partnership and of New Gauley Coal Corporation since 1988 and of the general partner of Great Northern Properties Limited Partnership since 1992. He was also Controller of Blackhawk Mining Co., Quintana Coal Co. and other related operations from 1985 to 1988. Prior to that time, Mr. Hudson worked in public accounting.
 
Kathy H. Roberts is Vice President, Investor Relations of GP Natural Resource Partners LLC. Ms. Roberts joined NRP in July 2002. She was the Principal of IR Consulting Associates from 2001 to July 2002 and from 1980 through 2000 held various financial and investor relations positions with Santa Fe Energy Resources, most recently as Vice President — Public Affairs. She is a Certified Public Accountant. Ms. Roberts currently serves on the Board of Directors of the National Association of Publicly Traded Partnerships and has served on the local board of directors of the National Investor Relations Institute and maintained professional


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affiliations with various energy industry organizations. She has also served on the Executive Committee and as a National Vice President of the Institute of Management Accountants.
 
Robert T. Blakely joined the Board of Directors of GP Natural Resource Partners LLC in January 2003. Mr. Blakely has extensive public company experience having served as Executive Vice President and Chief Financial Officer for several companies. He is currently the Chairman and Chief Executive Officer of Professional Racing Equipment, Inc., a leading distributor of racing components to NASCAR and professional road racing teams. From January 2006 until August 2007, he served as Executive Vice President and Chief Financial Officer of Fannie Mae, and from August 2007 to January 2008 as an Executive Vice President at Fannie Mae. From mid-2003 through January 2006, he was Executive Vice President and Chief Financial Officer of MCI, Inc. He previously served as Executive Vice President and Chief Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco, Inc. from 1981 until 1999 as well as a Managing Director at Morgan Stanley. More recently he founded and serves as President of Performance Enhancement Group, a private company that was formed to acquire manufacturers of high performance and racing components designed for automotive and marine-engine applications. He currently serves as a Trustee of the Financial Accounting Federation and is a trustee emeritus of Cornell University. He has served on the Board of Directors and as Chairman of the Audit Committee of Westlake Chemical Corporation since August 2004. In 2009, Mr. Blakely joined the Boards of Directors of GMAC Inc., where he serves as Chairman of the Audit Committee, and Greenhill & Co., where he serves as Chairman of the Nominating and Governance Committee.
 
David M. Carmichael joined the Board of Directors of GP Natural Resource Partners LLC in 2002. While Mr. Carmichael has been a private investor since June 1996, he has formerly served as Chairman and Chief Executive Officer at several public companies and currently serves on the board of directors of two public companies. Between 1994 and 1996, he served as Vice Chairman and Chairman of the Management Committee of KN Energy, Inc., a predecessor to Kinder Morgan, Inc. From 1985 until its merger with KN Energy, Inc. in 1994, Mr. Carmichael served as Chairman, Chief Executive Officer and President of American Oil and Gas Corporation. He formed CARCON Corporation in 1984, where he served as President and Chief Executive Officer until its merger into American Oil and Gas Corporation in 1986. From 1976 to 1984, Mr. Carmichael was Chairman and Chief Executive Officer of WellTech, Inc. He served in various senior management positions with Reading and Bates Corporation between 1965 and 1976. He has served on the Board of Directors of ENSCO International since 2001, Cabot Oil and Gas since 2006, and Tom Brown, Inc. from 1997 until 2004. Mr. Carmichael serves on the Nominating and Governance Committee and the Compensation Committee for Cabot and on the Compensation, Nominating and Governance Committees for ENSCO. He also currently serves as a trustee of the Texas Heart Institute.
 
J. Matthew Fifield is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Fifield brings coal mining and financial experience to NRP’s board of directors. Mr. Fifield joined NRP’s Board of Directors in January 2007. He currently serves as a Managing Director of Foresight Management, LLC, a Cline Group affiliate and is responsible for business development. Since 2005, he has also served as a Managing Director of both Adena Minerals, LLC and Cline Resource & Development Company, both Cline Group affiliates. From June 2004 until joining the Cline Group, Mr. Fifield worked at RCF Management LLC, a private equity firm focusing on metals and mining. While at RCF Management, he also served as President of Basin Perlite Company from August 2005 to October 2005. Mr. Fifield received his MBA from The University of Pennsylvania’s Wharton School of Business, which he attended from 2002 through 2004.
 
Robert B. Karn III joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Karn brings extensive financial and coal industry experience to the board of directors. He currently is a consultant and serves on the Board of Directors of various entities. He was the partner in charge of the coal mining practice worldwide for Arthur Andersen from 1981 until his retirement in 1998. He retired as Managing Partner of the St. Louis office’s Financial and Economic Consulting Practice. Mr. Karn is a Certified Public Accountant, Certified Fraud Examiner and has served as president of numerous organizations. He also currently serves on the Board of Directors of Peabody Energy Corporation, Kennedy Capital Management, Inc. and the Board of Trustees of Fiduciary Claymore MLP Opportunity Fund.


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S. Reed Morian joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive business experience having served as Chairman and Chief Executive Officer of several companies since the early 1980s and serving on the board of other companies. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian worked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief Executive Officer from 1981 to 2006. He has also served as Chairman, Chief Executive Officer and President of DX Holding Company since 1989. He formerly served on the Board of Directors for the Federal Reserve Bank of Dallas-Houston Branch from April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March 2005 until April 2009.
 
W. W. Scott, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Scott has extensive experience both as a commercial banker and as a Chief Financial Officer. Mr. Scott joined Mr. Robertson’s various companies in the mid-1980s, and retired in 1999. Mr. Scott was Executive Vice President and Chief Financial Officer of Quintana Minerals Corporation from 1985 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation from 1986 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Great Northern Properties Limited Partnership from 1992 to 1999. Since 1999, he has continued to serve as a director of the general partner of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation.
 
Stephen P. Smith joined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive public company financial experience in the power and energy industries to the board of directors. Mr. Smith has been the Executive Vice President and Chief Financial Officer for NiSource, Inc. since June 2008. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc, including Senior Vice President — Shared Services from January 2008 to June 2008, Senior Vice President and Treasurer from January 2004 to December 2007, and Senior Vice President — Finance from April 2003 to December 2003. From November 2000 to January 2003, Mr. Smith served as President and Chief Operating Officer — Corporate Services for NiSource Inc. Prior to joining NiSource, Mr. Smith served as Deputy Chief Financial Officer for Columbia Energy Group from November 1999 to November 2000 and Chief Financial Officer for Columbia Gas Transmission Corporation and Columbia Gulf Transmission Company from 1996 to 1999.
 
Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings extensive experience in the aggregates and coal mine development industry to the board of directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the late 1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer and contractor in the Mid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with Vecellio & Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996 to November 2002. Mr. Vecellio is the former Chairman of the American Road and Transportation Builders and is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations.
 
Corporate Governance
 
Board Attendance and Executive Sessions
 
The Board of Directors met ten times in 2009. During that period, every director attended all of the board meetings, with the exception of Mr. Fifield, who missed two meetings that involved discussions of acquisitions from the Cline Group, and Messrs. Morian, Carmichael, Vecellio and Scott, who each missed one meeting. Pursuant to our Corporate Governance Guidelines, the non-management directors meet in executive session on a quarterly basis. During 2009, our non-management directors met in executive session four times. The presiding director of these meetings was David Carmichael, the Chairman of our Compensation, Nominating and Governance Committee, or CNG Committee. In addition, our independent directors met one time in executive session in 2009. Mr. Carmichael was the presiding director at this meeting. Interested parties may communicate with our non-management directors by writing a letter to the Chairman of the CNG Committee, NRP Board of Directors, 601 Jefferson St., Suite 3600, Houston, Texas 77002.


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Independence of Directors
 
The Board of Directors has affirmatively determined that Messrs. Blakely, Carmichael, Karn, Smith and Vecellio are independent based on all facts and circumstances considered by the board, including the standards set forth in Section 303A.02(a) of the New York Stock Exchange’s listing standards. Although we had a majority of independent directors in 2009, because we are a limited partnership as defined in Section 303A of the New York Stock Exchange’s listing standards, we are not required to do so. The Board has an Audit Committee, Compensation, Nominating and Governance Committee and Conflicts Committee, each of which is staffed solely by independent directors. Our Audit Committee is comprised of Robert B. Karn III, who serves as chairman, Robert T. Blakely, Stephen P. Smith and David M. Carmichael. Mr. Karn, Mr. Smith and Mr. Blakely are “Audit Committee Financial Experts” as determined pursuant to Item 407 of Regulation S-K. In addition to his service on our audit committee and the audit committee for Westlake Chemical Corporation, in 2009 Mr. Blakely joined the audit committees of two additional public companies. In accordance with the rules of the New York Stock Exchange, our Board of Directors has made the determination that Mr. Blakely’s service on four audit committees does not impair his ability to serve effectively on our audit committee.
 
Report of the Audit Committee
 
Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements of the New York Stock Exchange. The Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements.
 
During the year 2009, at each of its meetings, the Committee met with the senior members of our financial management team, our general counsel and our independent auditors. The Committee had private sessions at certain of its meetings with our independent auditors at which candid discussions of financial management, accounting and internal control issues took place.
 
The Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 2009 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our financial reporting.
 
Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference for conservative policies when a range of accounting options is available.
 
The Committee also discussed with the independent auditors other matters required to be discussed by the auditors with the Committee by PCAOB Auditing Standard AU Section 380, Communication With Audit Committees. The Committee received and discussed with the auditors their annual written report on their independence from the partnership and its management, which is made under Rule 3526, Communication With Audit Committees Concerning Independence, and considered with the auditors whether the provision of non-audit services provided by them to the partnership during 2009 was compatible with the auditors’ independence.
 
In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Committee reviews our quarterly and annual reporting on Form 10-Q and Form 10-K prior to filing with the Securities and Exchange Commission. In 2009, the Committee also reviewed quarterly earnings announcements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Committee relies on the work and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report,


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express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting principles.
 
In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, and the Board has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2009, for filing with the Securities and Exchange Commission.
 
Robert B. Karn III, Chairman
Robert T. Blakely
Stephen P. Smith
David M. Carmichael
 
Compensation, Nominating and Governance Committee Authority
 
Executive officer compensation is administered by the CNG Committee, which is comprised of four members. Mr. Carmichael, the Chairman, and Mr. Karn have served on this committee since 2002, Mr. Blakely joined the committee in early 2003, and Mr. Vecellio joined the committee in 2007. The CNG Committee has reviewed and approved the compensation arrangements described in the Compensation Discussion and Analysis section of this Form 10-K. Our board of directors appoints the CNG Committee and delegates to the CNG Committee responsibility for:
 
  •  reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates to our business;
 
  •  reviewing and recommending the annual and long-term incentive plans in which our executive officers participate; and
 
  •  reviewing and approving compensation for the board of directors.
 
Our board of directors has determined that each committee member is independent under the listing standards of the New York Stock Exchange and the rules of the Securities and Exchange Commission.
 
Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the design and implementation of compensation programs for directors and executive officers and other data that the CNG Committee considers as appropriate. In addition, the CNG Committee has the sole authority to retain and terminate any outside counsel or other experts or consultants engaged to assist it in the evaluation of compensation of our directors and executive officers.
 
Section 16(a) Beneficial Ownership Reporting Compliance
 
Section 16(a) of the Securities and Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of their equity securities. These people are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required other than one Form 5 for Mr. Karn, we believe that our officers and directors and persons who beneficially own more than ten percent of a registered class of our equity securities complied with all filing requirements with respect to transactions in our equity securities during 2009, with the exception of Mr. Scott, who had one late Form 4.
 
Partnership Agreement
 
Investors may view our partnership agreement and the amendments to the partnership agreement on our website at www.nrplp.com. The partnership agreement and the amendments are also filed with the Securities and Exchange Commission and are available in print to any unitholder that requests them.
 
Corporate Governance Guidelines and Code of Business Conduct and Ethics
 
We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that applies to our management, and complies with Item 406 of Regulation S-K. Our Corporate


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Governance Guidelines and our Code of Business Conduct and Ethics are available on the internet at www.nrplp.com and are available in print upon request.
 
NYSE Certification
 
Pursuant to Section 303A of the NYSE Listed Company Manual, in 2009, Corbin J. Robertson, Jr. certified to the NYSE that he was not aware of any violation by the Partnership of NYSE corporate governance listing standards.
 
Item 11.   Executive Compensation
 
Compensation Discussion and Analysis
 
Overview
 
As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. We have no employees, and our executive officers based in Houston, Texas are employed by Quintana Minerals Corporation and our executive officers based in Huntington, West Virginia are employed by Western Pocahontas Properties Limited Partnership, both of which are our affiliates. For a more detailed description of our structure, please see “Item 1. Business — Partnership Structure and Management” in this Form 10-K. Although our executives’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse those companies based on the time allocated to NRP by each executive officer. Our reimbursement for the compensation of executive officers is governed by our partnership agreement.
 
Executive Officer Compensation Strategy and Philosophy
 
Under our partnership agreement, we are required to distribute all of our available cash each quarter. Our primary business objective is to generate cash flows at levels that can sustain regular quarterly increases in the cash distributions paid to our investors. Our executive officer compensation strategy has been designed to motivate and retain our executive officers and to align their interests with those of our unitholders. Our primary objective in determining the compensation of our executive officers is to encourage them to build the partnership in a way that ensures increased cash distributions to our unitholders and growth in our asset base while maintaining the long-term stability of the partnership. We do not tie our compensation to achievement of specific financial targets or fixed performance criteria, but rather evaluate the appropriate compensation on an annual basis in light of our overall business objectives.
 
In accordance with our objective of increasing the quarterly distribution, we believe that optimal alignment between our unitholders and our executive officers is best achieved by compensating our executive officers through sharing a percentage of the incentive distribution rights and through distribution equivalent rights tied to long-term equity-based compensation. Our compensation for executive officers consists of four primary components:
 
  •  base salaries;
 
  •  annual cash incentive awards, including bonuses and cash payments made by our general partner based on a percentage of the cash it receives from its incentive distribution rights;
 
  •  long-term equity incentive compensation; and
 
  •  perquisites and other benefits.
 
Mr. Robertson does not receive a salary or an annual bonus in his capacity as CEO. Rather, for the reasons discussed in greater detail below, Mr. Robertson is compensated exclusively through long-term phantom unit grants awarded by the CNG Committee and the incentive distribution rights owned by our general partner and its affilitates. Mr. Robertson also directly or indirectly owns in excess of 25% of the outstanding units of NRP, and thus his interests are directly aligned with our unitholders.
 
In November and December 2009, our CNG Committee reviewed the performance of the executive officers and the amount of time expected to be spent by each NRP officer on NRP business. All of our executive officers other than Mr. Robertson spend nearly 90% or more of their time on NRP matters and NRP bears the allocated cost of their time spent on NRP matters. Mr. Robertson has historically spent approximately


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50% of his time on NRP matters. Based on its review, the CNG Committee approved the salaries at the same levels as in 2009 for each of the executive officers other than Mr. Robertson.
 
In February 2010, the CNG Committee met to approve the year-end bonuses and long-term incentive awards for the executive officers. The CNG Committee considered the performance of the partnership, the performance of the individuals and the outlook for the future in determining the amounts of the awards. Because we are a partnership, tax and accounting conventions make it more costly for us to issue additional common units or options as incentive compensation. Consequently, we have no outstanding options or restricted units and have no plans to issue options or restricted units in the future. Instead, we have issued phantom units to our executive officers that are paid in cash based on the average closing price of our common units for the 20-day trading period prior to vesting. The phantom units typically vest four years from the date of grant. In connection with the phantom unit awards granted in 2008, 2009 and 2010, the CNG Committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on our common units. The DERs have a four-year vesting period. Through these awards, each executive officer’s interest is aligned with those of our unitholders in increasing our quarterly cash distributions, our unit price and maintaining a steady growth profile for NRP.
 
Role of Compensation Experts
 
The CNG Committee did not retain any consultants to evaluate compensation of officers or directors in 2009. The CNG Committee historically has utilized consultants every other year to get a basic sense of the market, but has considered the advice of the consultant as only one factor among the other items discussed in this compensation discussion and analysis. The most recent review was conducted in 2008. For a more detailed description of the CNG Committee and its responsibilities, please see “Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance” in this Form 10-K.
 
Role of Our Executive Officers in the Compensation Process
 
Mr. Robertson and Mr. Carter provided recommendations to the CNG Committee in its evaluation of the 2009 compensation programs for our executive officers. Mr. Carter provided Mr. Robertson with recommendations relating to the executive officers, other than himself, that are based in Huntington. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of the executive officers, including the Houston-based officers other than himself. Mr. Robertson and Mr. Carter relied on their personal experience in setting compensation over a number of years in determining the appropriate amounts for each employee, and considered each of the factors described elsewhere in this compensation discussion and analysis. Mr. Robertson attended the CNG Committee meetings at which the committee deliberated and approved the compensation, but was excused from the meetings when the CNG Committee discussed his compensation. No other named executive officer assumed an active role in the evaluation or design of the 2009 executive officer compensation programs.
 
Components of Compensation
 
Base Salaries
 
With the exception of Mr. Robertson, who, as described above, does not receive a salary for his services as Chief Executive Officer, our named executive officers are paid an annual base salary by Quintana and Western Pocahontas for services rendered to us by the executive officers during the fiscal year. We then reimburse Quintana and Western Pocahontas based on the time allocated by each executive officer to our business. The base salaries of our named executive officers are reviewed on an annual basis as well as at the time of a promotion or other material change in responsibilities. The CNG Committee reviews and approves the full salaries paid to each executive officer by Quintana and Western Pocahontas, based on both the actual time allocations to NRP in the prior year and the anticipated time allocations in the coming year. Adjustments in base salary are based on an evaluation of individual performance, our partnership’s overall performance during the fiscal year and the individual’s contribution to our overall performance.
 
Annual Cash Incentive Awards
 
Each executive officer, other than Mr. Robertson, participated in two cash incentive programs in 2009. The first program is a discretionary cash bonus award approved in February 2010 by the CNG Committee


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based on the same criteria used to evaluate the annual base salaries. The bonuses awarded with respect to 2009 under this program are disclosed in the Summary Compensation Table under the Bonus column. As with the base salaries, there are no formulas or specific performance targets related to these awards. As a result of the recession and the lower revenues that NRP generated in 2009, we were only able to raise the distribution by 1% over the course of the year, and in the third and fourth quarters of 2009, the general partner and the other holders of the incentive distribution rights waived their rights to receive the highest splits under the incentive distribution rights in order to facilitate a large acquisition. These factors were considered by the CNG Committee in determining to award lower bonuses to the executive officers in 2009 versus 2008.
 
Under the second cash incentive program, our general partner has set aside 7.5% of the cash distributions it receives on an annual basis with respect to its incentive distribution rights under our partnership agreement for awards to our executive officers, including Mr. Robertson. Although Mr. Robertson has the discretion to determine the amount of the 7.5% that is allocated to each executive officer, the cash awards that our officers receive under this plan are reviewed by the CNG Committee and taken into account when making determinations with respect to salaries, bonuses and long-term incentive awards. Because they are ultimately reimbursed by the general partner and not NRP, the incentive payments made with respect to this program do not have any impact on our financial statements or cash available for distribution to our unitholders. Since the cost of these awards is not borne by NRP, we have not disclosed the amounts of these awards in the Summary Compensation Table, but have included the amounts separately in a footnote to the table. We believe that these awards align the interests of our executive officers directly with our unitholders in consistently increasing our quarterly distributions. As evidence of this alignment, the waiver by the general partner of a portion of its incentive distribution rights in the third and fourth quarters of 2009 reduced the amount of cash available to be awarded to the executive officers under that program.
 
Long-Term Incentive Compensation
 
At the time of our initial public offering, we adopted the Natural Resource Partners Long-Term Incentive Plan for our directors and all the employees who perform services for NRP, including the executive officers. We consider long-term equity-based incentive compensation to be the most important element of our compensation program for executive officers because we believe that these awards keep our officers focused on the growth of NRP, particularly the growth of quarterly distributions and their impact on our unit price, over an extended time horizon.
 
Consistent with this approach, in 2008 our CNG Committee recommended, and our Board approved, an amendment to our Long-Term Incentive Plan to add distribution equivalent rights as a possible award to be granted under the plan. The distribution equivalent rights are contingent rights, granted in tandem with phantom units, to receive an amount in cash equal to the cash distributions made by NRP with respect to the common units during the period in which the phantom units are outstanding.
 
Our CNG Committee has generally approved annual awards of phantom units that vest four years from the date of grant. The amounts included in the compensation table reflect the grant date fair value of the unit awards determined in accordance with Financial Accounting Standards Board stock compensation authoritative guidance. We have structured the phantom unit awards so that our executive officers and directors directly benefit along with our unitholders when our unit price increases, and experience reductions in the value of their incentive awards when our unit price declines.
 
In connection with its review of incentive compensation in February 2010, the CNG Committee determined not to increase the annual phantom unit grants to any of the named executive officers and approved a lower award in 2010 for Mr. Robertson as compared the award he received in 2009.
 
Perquisites and Other Personal Benefits
 
Both Quintana and Western Pocahontas maintain employee benefit plans that provide our executive officers and other employees with the opportunity to enroll in health, dental and life insurance plans. Each of these benefit plans require the employee to pay a portion of the health and dental premiums, with the company paying the remainder. These benefits are offered on the same basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee allocates time to our business.


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Quintana and Western Pocahontas also maintain 401(k) and defined contribution retirement plans. Quintana matches 100% of the first 4.5% of the employee contributions under the 401(k) plan and Western Pocahontas matches the employee contributions at a level of 100% of the first 3% of the contribution and 50% of the next 3% of the contribution. In addition, each company contributes 1/12 of each employee’s base salary to the defined contribution retirement plan on an annual basis. As with the other contributions, any amounts contributed by Quintana and Western Pocahontas are reimbursed by us based on the time allocated by the employee to our business. The payments made to Messrs. Carter, Dunlap, Hogan and Wall under the defined contribution plan exceeded $10,000 in each of 2007, 2008 and 2009, but did not exceed $20,000 for any individual in any year. None of NRP, Quintana or Western Pocahontas maintain a pension plan or a defined benefit retirement plan. As noted in the Summary Compensation Table, in 2007, 2008 and 2009 we also reimbursed Quintana and Western Pocahontas for car allowances provided to Messrs. Carter, Dunlap and Wall.
 
Unit Ownership Requirements
 
We do not have any policy or guidelines that require specified ownership of our common units by our directors or executive officers or unit retention guidelines applicable to equity-based awards granted to directors or executive officers. As of December 31, 2009, our named executive officers held 231,000 phantom units that have been granted as compensation. In addition, Mr. Robertson directly or indirectly owns in excess of 25% of the outstanding units of NRP.
 
Securities Trading Policy
 
Our insider trading policy states that executive officers and directors may not purchase or sell puts or calls to sell or buy our units, engage in short sales with respect to our units, or buy our securities on margin.
 
Tax Implications of Executive Compensation
 
Because we are a partnership, Section 162(m) of the Internal Revenue Code does not apply to compensation paid to our named executive officers and accordingly, the CNG Committee did not consider its impact in determining compensation levels in 2007, 2008 or 2009. The CNG Committee has taken into account the tax implications to the partnership in its decision to limit the long-term incentive compensation to phantom units as opposed to options or restricted units.
 
Accounting Implications of Executive Compensation
 
The CNG Committee has considered the partnership accounting implications, particularly the “book-up” cost, of issuing equity as incentive compensation, and has determined that phantom units offer the best accounting treatment for the partnership while still motivating and retaining our executive officers.
 
Report of the Compensation, Nominating and G