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NATURAL RESOURCE PARTNERS LP - Annual Report: 2006 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
 
 
 
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2006
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   (I.R.S. Employer
incorporation or organization)
  Identification Number)
     
601 Jefferson, Suite 3600
Houston, Texas
  77002
(Address of principal executive offices)   (Zip Code)
 
(713) 751-7507
(Registrant’s Telephone Number, Including Area Code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name Of Each Exchange On Which Registered
 
Common Units representing limited partnership interests
  New York Stock Exchange
Subordinated 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 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, or a non-accelerated filer
 
o Large Accelerated Filer þ Accelerated Filer o Non-accelerated Filer
 
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 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 Units outstanding, for this purpose, as if they were affiliates of the registrant) was approximately $649.7 million for the Common Units and $225.9 million for the Subordinated Units on June 30, 2006 based on a price of $54.20 per unit for the Common Units and $50.94 per unit for the Subordinated Units. These prices are the respective closing prices of the Units as reported on the New York Stock Exchange on that date.
 
As of February 27, 2007, there were 25,976,795 Common Units outstanding, 5,676,817 Subordinated Units outstanding and 541,956 Class B Units outstanding. The Class B Units are not publicly traded.
 
DOCUMENTS INCORPORATED BY REFERENCE.
 
None.


 

 
Table of Contents
 
                 
Item
      Page
 
1.
  Business   3
1A.
  Risk Factors   14
1B.
  Unresolved Staff Comments   18
2.
  Properties   18
3.
  Legal Proceedings   25
4.
  Submission of Matters to a Vote of Security Holders   25
 
5.
  Market for Registrant’s Common Units, Subordinated Units, Related Unitholder Matters and Issuer Purchases of Equity Securities   26
6.
  Selected Financial Data   28
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   64
9A.
  Controls and Procedures   64
9B.
  Other Information   65
 
10.
  Directors and Executive Officers of the General Partner and Corporate Governance   66
11.
  Executive Compensation   72
  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters   80
13.
  Certain Relationships and Related Transactions, and Director Independence   81
14.
  Principal Accountant Fees and Services   88
 
15.
  Exhibits and Financial Statement Schedules   91
 Form of Series D Note
 List of Subsidiaries
 Consent of Ernst & Young LLP
 Certification of CEO Pursuant to Section 302
 Certification of CFO Pursuant to Section 302
 Certification of CEO Pursuant to Section 1350
 Certification of CFO Pursuant to Section 1350
 Audited Balance Sheet


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Forward-Looking Statements
 
Statements included in this Form 10-K are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements.
 
Such forward-looking statements include, among other things, statements regarding capital expenditures and acquisitions, expected commencement dates of mining, projected quantities of future production by our lessees producing from our reserves, and projected demand or supply for coal 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, 2006, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves in eleven states. 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, 2006, our coal reserves were subject to 180 leases with 70 lessees. In 2006, our lessees produced 52.1 million tons of coal from our properties and our coal royalty revenues were $147.8 million.
 
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. Neither of these businesses currently contribute a large percentage of our total revenues, but we anticipate that we will grow these businesses in the future.
 
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. Pending the appointment of an additional independent director by Adena, we currently have eight directors, four of whom are independent.
 
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, Chief Executive Officer and controlling stockholder 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 are located at P.O. Box 2827, 1035 Third Avenue, Suite 300, Huntington, West Virginia 25727 and the telephone number is (304) 522-5757. Our principal executive offices are located at 601 Jefferson Street, Suite 3600, Houston, Texas 77002 and our phone number is (713) 751-7507.
 
Coal Royalty Business
 
Coal royalty businesses are principally engaged in the business of owning and managing 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


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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 often include the right to renegotiate rents and royalties for the extended term.
 
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. If permitted by the terms of the lease, 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 coal prices, lessees’ supply contracts and, to a lesser extent, fluctuations in the spot market prices for coal. 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 when coal production commences.
 
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 health care legacy costs, black lung benefits and workmen’s compensation costs, associated with operating the mines. We typically pay property taxes and then are reimbursed by the lessee for the taxes on the 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.
 
Recent Acquisitions
 
We are a growth-oriented company and have closed a number of accretive acquisitions over the last several years. Our most recent acquisitions are briefly described below.
 
2007 Acquisitions
 
Dingess-Rum.  On January 16, 2007, we acquired 92 million tons of coal reserves and approximately 33,700 acres of surface and timber in Logan, Clay and Nicholas Counties in West Virginia from Dingess-Rum Properties, Inc. As consideration for the acquisition, we issued 2,400,000 common units to Dingess-Rum in a private placement.
 
Cline.  On January 4, 2007, we acquired 49 million tons of coal reserves in Williamson County, Illinois and Mason County, West Virginia that are leased to affiliates of The Cline Group. In addition, we acquired transportation assets and related infrastructure at those mines. As consideration for the transaction we issued 3,913,080 common units and 541,956 Class B units in a private placement. Through its affiliate Adena Minerals, LLC, The Cline Group has also received a 22% interest in our general partner and in the incentive distribution rights of NRP in return for providing NRP with the exclusive right to acquire additional reserves, royalty interests and certain transportation infrastructure relating to future mine developments by The Cline Group. Simultaneous with the closing of this transaction, we signed a definitive agreement to purchase the reserves and transportation infrastructure at Cline’s Gatling Ohio complex. This transaction will close upon commencement of coal production, which is currently expected to occur in 2008. At the time of closing, NRP will issue Adena 2,280,000 additional Class B units, and the general partner of NRP will issue Adena an additional 9% interest in the general partner and the incentive distribution rights.


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2006 Acquisitions
 
Quadrant.  On December 29, 2006, we acquired an estimated 70 million tons of aggregate reserves located in DuPont, Washington for $23.5 million in cash and assumed a utility local improvement obligation of approximately $3.0 million. Of these reserves, approximately 25 million tons are currently permitted. We will pay an additional $7.5 million when the remaining tons are permitted. If the permit is not obtained by December 2016, the unpermitted tons will revert back to Quadrant. We funded this acquisition with cash and borrowings under our credit facility.
 
Bluestone.  On December 18, 2006, we acquired approximately 20 million tons of low vol metallurgical coal reserves that are located above our Pinnacle reserves in Wyoming County, West Virginia for $20 million. We funded this acquisition with borrowings under our credit facility.
 
D.D. Shepherd.  On December 1, 2006, we acquired nearly 25,000 acres of land containing in excess of 80 million tons of coal reserves for $110 million. The property is located in Boone County, West Virginia adjacent to other NRP property and consists of both metallurgical and steam coal reserves, gas reserves, surface and timber. We funded this acquisition with borrowings under our credit facility.
 
Red Fox.  On September 1, 2006, we acquired the Red Fox preparation plant and coal handling facility located in McDowell County, West Virginia for approximately $8.1 million, of which $4.1 million was paid at closing and the remainder was paid during the third and fourth quarters as construction was completed. This acquisition was the second under our memorandum of understanding with Taggart Global, LLC (formerly Sedgman USA, LLC). The plant will handle an estimated 20 million tons of coal reserves during its life. The initial $4.1 million payment paid at closing was funded through cash and borrowings under our credit facility and the remaining payments were funded with cash.
 
Coal Mountain.  On August 24, 2006, we acquired the Coal Mountain preparation plant, handling facility and rail load-out facility located in Wyoming County, West Virginia for $16.1 million under our memorandum of understanding with Taggart Global. We expect that approximately 35 million tons of coal will be processed through this facility during its life. We paid for the facilities with cash and with borrowings under our credit facility as construction was completed in phases during the third and fourth quarters.
 
Williamson Development.  On January 20, 2006 and August 15, 2006, we closed the second and third phases of the Williamson Development acquisition in Illinois for $35 million each. We funded the January 20, 2006 acquisition with proceeds from the issuance of senior notes and the August 15, 2006 acquisition with borrowings under our credit facility.
 
Allegany County, Maryland.  On June 29, 2006, we acquired 3.3 million tons of coal in Allegany County, Maryland for $5.5 million in cash.
 
Indiana Reserves.  On May 26, 2006, we acquired 16.3 million tons of coal reserves and an overriding royalty interest on an additional 2.4 million tons for $10.85 million in cash. These reserves are located in Pike, Warrick and Gibson Counties in Indiana.


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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, 2006, 2005 and 2004. 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,  
    2006     2005     2004     2006     2005     2004  
    (In thousands)     ($ per ton)  
 
Area
                                               
Appalachia
                                               
Northern
  $ 10,231     $ 11,306     $ 7,084     $ 1.92     $ 1.89     $ 1.70  
Central
    100,487       93,008       76,583       3.14       2.84       2.34  
Southern
    20,469       25,089       14,874       3.83       4.01       2.86  
                                                 
Total Appalachia
    131,187       129,403       98,541       3.07       2.87       2.34  
Illinois Basin
    5,325       4,288       3,852       1.85       1.54       1.23  
Northern Powder River Basin
    11,240       8,446       4,063       1.72       1.46       1.30  
                                                 
Total
  $ 147,752     $ 142,137     $ 106,456     $ 2.84     $ 2.65     $ 2.20  
                                                 
 
The following table sets forth production data and reserve information for the properties that we owned or controlled for the years ending December 31, 2006, 2005 and 2004. 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, 2006  
    2006     2005     2004     Underground     Surface     Total  
    (Tons in thousands)  
 
Area
                                               
Appalachia
                                               
Northern
    5,329       5,977       4,179       399,641       7,804       407,445  
Central
    31,991       32,790       32,702       1,138,728       107,077       1,245,804  
Southern
    5,347       6,263       5,208       159,660       35,987       195,647  
                                                 
Total Appalachia
    42,667       45,030       42,089       1,698,028       150,868       1,848,896  
Illinois Basin
    2,877       2,781       3,138       103,819       19,194       123,013  
Northern Powder River Basin
    6,548       5,795       3,130             125,323       125,323  
                                                 
Total
    52,092       53,606       48,357       1,801,848       295,384       2,097,232  
                                                 
 
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, 2006, approximately 36% 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


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reserves in the Illinois Basin and the Northern Powder River Basin. In 2006, approximately 28% 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, 2006.
 
Sulfur Content, Typical Quality and Type of Coal
 
                                                                         
          Sulfur Content     Typical Quality     Type of Coal  
          Low
    Medium
    High
                               
    Compliance
    (less than
    (1.0% to
    (greater
          Heat Content
    Sulfur
             
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
    43,300       51,879       25,824       329,742       407,445       13,083       2.77       397,883       9,562  
Central
    598,239       931,001       274,660       40,143       1,245,804       13,042       0.87       791,413       454,391  
Southern
    110,795       141,531       41,891       12,224       195,647       13,635       0.90       147,753       47,894  
                                                                         
Total Appalachia
    752,333       1,124,412       342,375       382,110       1,848,896                       1,337,049       511,847  
Illinois Basin
          701       5,147       117,165       123,013       11,605       2.48       123,013        
Northern Powder River Basin
          125,323                   125,323       8,800       0.65       125,323        
                                                                         
Total
    752,333       1,250,436       347,522       499,274       2,097,232                       1,585,385       511,847  
                                                                         
 
 
(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.
 
In 2005, we engaged several independent engineering firms to conduct reserve studies of our existing properties. However, as a result of the extensive nature of our reserve holdings and the large number of acquisitions that we consummate on an annual basis, this study will be an ongoing process. As of December 31, 2006, these studies had been completed with respect to approximately 44% of the tons we owned when we began the process, and a study is currently ongoing with respect to another 20% of the initial reserves. In connection with acquisitions, we have either commissioned new studies or relied on 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. 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 decreased royalties from lower than expected production by our lessees.


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Coal Transportation and Processing Revenues
 
In the second half of 2006, we acquired two preparation plants and coal handling facilities under our memorandum of understanding with Taggart Global. Together with a third coal preparation plant and rail load-out facility that we acquired in Greenbrier County, West Virginia in 2005, these facilities generated approximately $1.5 million in revenues in 2006. 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, as part of the January 2007 Cline transaction, we acquired coal handling and transportation infrastructure associated with the Gatling mining complex in West Virginia and beltlines and rail load-out facilities associated with Williamson Energy’s Pond Creek No. 1 mine in Illinois. We also entered into an agreement to purchase the transportation infrastructure as well as the reserves at Cline’s Gatling Ohio complex. This complex is located in Meigs County, Ohio directly across the river from Cline’s West Virginia operation. In contrast to our typical royalty structure, we are operating the coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We anticipate that these assets will contribute significant revenues to NRP in future years.
 
Aggregates Royalty Revenues, Reserves and Production
 
In December 2006, we acquired an estimated 70 million tons of aggregate reserves located in DuPont, Washington for $23.5 million in cash and assumed a utility local improvement obligation of approximately $3.0 million. Of these reserves, approximately 25 million tons are currently permitted. We will pay an additional $7.5 million when the remaining tons are permitted, provided, however, that if they are not permitted by December 2016, the title to the remaining tons will revert back to Quadrant. The acquisition was effective as of December 1, 2006 and for the month of December we received $0.6 million in royalty revenues on 412,000 tons of production.
 
Oil, Gas and Timber Properties
 
For the year ended December 31, 2006, we derived approximately 5% of our total revenues from oil, gas and timber royalties in Kentucky, Virginia and Tennessee. The 2006 revenues include approximately $3.5 million related to the sale of substantially all of our then-existing timber properties. Subsequent to that sale we acquired approximately 24,000 acres of timber rights in the D.D. Shepard acquisition in December 2006 and another 31,000 acres of timber rights in the Dingess-Rum acquisition in January 2007. Nevertheless, we do not own the oil, gas or timber rights on the vast majority of our properties, and do not expect to receive material oil, gas or timber revenues in 2007.
 
Significant Customers
 
In 2006, Alpha Natural Resources, Inc. and its various subsidiaries, as lessees, collectively provided approximately 14% of our total revenues. Although the loss of Alpha as a lessee could have a material adverse effect on us, we do not believe that the loss of a single mine on any of our properties would have a material adverse effect on us. No other lessee contributed more than 10% of our total revenues in 2006.
 
Competition
 
We face competition from other land companies and from coal producers 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. The top ten producers have increased their share of total domestic coal production from 38% in 1976 to 64% in 2005. 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


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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 environmental and government regulations, technological developments and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, oil 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 in the industry 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 closing, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because our lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. 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. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.
 
In addition, the 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 may be adopted that have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and may require our lessees or their customers to change operations significantly or incur substantial costs that could impact us.
 
Air Emissions.  The Federal Clean Air Act and corresponding state and local laws and regulations affect all aspects of our business. The Clean Air Act directly impacts our lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control 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 implementation plans, could make coal a less attractive fuel alternative 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.
 
The EPA’s Acid Rain Program, provided in Title IV of the Clean Air Act, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the


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EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulphurization systems, or “scrubbers,” or by reducing electricity generating levels.
 
The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require 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 will permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010, respectively. CAIR requires 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.
 
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. While currently the subject of extensive controversy and litigation, 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.
 
The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. 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 in “non-attainment” with the new national ambient air quality standard for fine particulate matter. In November 2005, the EPA published proposed rules addressing how states would implement plans to bring applicable non-attainment regions into compliance with the new air quality standard. Under the EPA’s proposed rulemaking, states would have until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our lessees’ mining operations and their customers could be affected when the new standards are implemented by the applicable states.
 
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. As part of the new rules, affected states must develop implementation plans by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. 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.
 
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 certain 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 Emissions.  The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls 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.
 
In 2002, the United States withdrew its support for the Kyoto Protocol As the Kyoto Protocol becomes effective, there will likely be increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. The United States Congress has considered bills in the past that would regulate domestic carbon dioxide emissions, but such bills have not yet received sufficient Congressional support for passage into law. 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


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northeastern states agreed to implement a regional cap-and-trade program to stabilize carbon dioxide emissions from regional power plants beginning in 2009.
 
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. 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. In conjunction with mining the property, our coal lessees are contractually obligated under the terms of our leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation of the mined areas by grading, shaping and reseeding the soil. 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.
 
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 statues 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 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 Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington 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 vacated by the Fourth Circuit Court of Appeals in November 2005, 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 in adjoining jurisdictions, some of our lessees may be required to apply for individual discharge permits pursuant to Section 404


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of the Clean Water Act in areas where they would have otherwise utilized Nationwide Permit 21. Such a change could 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.
 
The Clean Water Act also requires states to develop anti-degradation policies to ensure non-impaired waterbodies 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, as part of the Mine Health and Safety Acts of 1969 and 1977, 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.
 
Recent mining accidents in West Virginia and Kentucky 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, Kentucky Governor Ernie Fletcher 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 the President signed new mining safety legislation that mandates similar improvements in mine safety practices; increases civil and criminal penalties for non-compliance; requires the creation of additional mine rescue teams, and expands the scope of federal oversight, inspection and enforcement activities. Earlier, the federal Mine Safety 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. Implementing and complying with these new laws and regulations could adversely affect our lessees’ coal production and could therefore have an adverse affect on our coal royalty revenues and our ability to make distributions.
 
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


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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 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 55 employees who directly support our operations. None of these employees are subject to a collective bargaining agreement. Some of the employees of our lessees and sub-lessees are subject to collective bargaining agreements.
 
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. All of our owned properties are subject to leases, and revenues are earned based on the volume 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” 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.


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Item 1A.   Risk Factors
 
We may not have sufficient cash from operations to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
The amount of cash we can distribute on our units principally depends upon the amount of royalties we receive from our lessees, which will fluctuate from quarter to quarter based on, among other things:
 
  •  the amount of coal our lessees are able to produce from our properties;
 
  •  the price at which our lessees are able to sell coal; and
 
  •  prevailing economic conditions.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:
 
  •  the level of our operating costs;
 
  •  the level of our general and administrative costs;
 
  •  the costs of acquisitions, if any;
 
  •  our debt service requirements;
 
  •  fluctuations in our working capital;
 
  •  the level of capital expenditures we make;
 
  •  restrictions on distributions contained in our debt instruments;
 
  •  our ability to borrow under our credit facility to pay distributions; and
 
  •  the amount of cash reserves established by our general partner in its sole discretion in the conduct of our business.
 
You should also be aware that our ability to pay quarterly distributions depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.
 
We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves or obtain other mineral reserves through acquisitions.
 
Because our reserves decline as our lessees mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves or other mineral reserves that are economically recoverable. If we are unable to replace or increase our coal reserves or acquire other mineral reserves on acceptable terms, our royalty revenues will decline as our reserves are depleted. 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.


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A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our reserves.
 
The prices our lessees receive for their coal depend upon factors beyond their or our control, including:
 
  •  the supply of and demand for domestic and foreign coal;
 
  •  weather conditions;
 
  •  the proximity to and capacity of transportation facilities;
 
  •  worldwide economic conditions;
 
  •  domestic and foreign governmental regulations and taxes;
 
  •  the price and availability of alternative fuels; 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 change in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues.
 
According to the U.S. Department of Energy, domestic electric power generation accounts for approximately 90% of domestic coal consumption. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as natural gas, nuclear, fuel oil and hydroelectric power and environmental and other governmental regulations. We expect new power plants will be built to produce electricity. Some of these new power plants will be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the federal Clean Air Act may result in more electric power generators shifting from coal to natural-gas-fired power plants. In addition, in recent years there has been significant political discussion of the connection between the emission of greenhouse gases and global warming. The environmental lobby is applying substantial pressure on utilities to limit the construction of new coal-fired generation plants in favor of alternative sources of energy. To the extent that these efforts are successful, it could reduce the demand for our coal.
 
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties.
 
Transportation costs represent a significant portion of the total cost of coal for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal 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 coal producers in other parts of the country.
 
Our lessees depend upon railroads, barges, trucks and beltlines to deliver coal 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 coal to their customers. Our lessees’ transportation providers may face difficulties in the future that may impair the ability of our lessees to supply coal to their customers, resulting in decreased coal royalty revenues to us.


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Our lessees’ coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us.
 
Our coal royalty revenues are largely dependent on our lessees’ level of production from our coal 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 coal deposits and the amount of rock embedded in or overlying the coal deposit;
 
  •  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.
 
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.
 
Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties.
 
Our lessees may incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species 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. 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 coal royalty revenues could be adversely affected.
 
New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements and the protection of endangered species, could further regulate or tax the coal 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 coal royalty revenues.
 
If our lessees do not manage their operations well, their production volumes and our coal 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 coal mined;
 
  •  mine plans, including the amount to be mined and the method of mining;
 
  •  processing and blending coal;
 
  •  credit risk of their customers;
 
  •  permitting;


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  •  insurance and surety bonding;
 
  •  acquisition of surface rights and other mineral estates;
 
  •  employee wages;
 
  •  coal transportation arrangements;
 
  •  compliance with applicable laws, including environmental laws;
 
  •  negotiations and relations with unions; and
 
  •  mine closure and reclamation.
 
A failure on the part of one of our lessees to make coal 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 coal 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 coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.
 
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 2006, approximately 28% of the coal production and 33% of the coal royalty revenues from our properties were from metallurgical coal. The steel industry has increasingly relied on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that our lessees mine could continue to decrease. Additionally, 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 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, these mines may not be economically viable and may close.
 
Lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.
 
Coal supply contracts do not generally require operators to satisfy their obligations to their customers with coal mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with coal 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 coal specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower coal royalty revenues.
 
Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves.
 
Our reserve estimates may vary substantially from the actual amounts of coal 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 coal 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 coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs;


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  •  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 coal 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 coal royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 2.   Properties
 
Major Coal Properties
 
The following is a summary of our major coal properties in each coal producing region:
 
Northern Appalachia
 
AFG-Southwest PA.  The AFG property is located in Washington County, Pennsylvania. We acquired this property in November 2005. In 2006, 3.0 million 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.
 
Kingwood.  The Kingwood property is located in Preston County, West Virginia. In 2006, 1.3 million tons were produced from this property. We lease this property to Kingwood Mining Company, LLC, a subsidiary of Alpha Natural Resources L.P. Coal is produced from an underground mine. It is transported by belt to a preparation plant operated by the lessee. Coal is shipped primarily by CSX railroad to utilities such as Allegheny Power, Mirant and VEPCO.
 
Sincell.  The Sincell property is located in Garrett County, Maryland. In 2006, 728,000 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 mine and a surface mine. It is transported by belt or 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.  The Gatling property is located in Mason County, West Virginia. We acquired the property in January 2007 as part of the larger Cline transaction. Coal from this property will be mined from an underground mine and transported via belt line to a preparation plant on the property. Clean coal will be transported via beltline either directly to the customer or to a barge loading facility. Production on the property began in the fourth quarter of 2006.
 
The map on the following page shows the location of our properties in Northern Appalachia.
 


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Central Appalachia
 
D.D. Shepard.  The D.D. Shepard property is located in Boone County, West Virginia. This property is primarily leased to a subsidiary of Peabody Energy. We acquired the property effective December 1, 2006, and 486,000 tons were produced from this property in December. Both steam and metallurgical coal is 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 Appalachian Power.
 
VICC/Alpha.  The VICC/Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2006, 6.7 million tons were produced from this property. We primarily lease this property to Alpha Land and Reserves, LLC. 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


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customers. Major customers include American Electric Power, Southern Company, Tennessee Valley Authority, VEPCO and U.S. Steel.
 
Lynch.  The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2006, 5.3 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 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.
 
Pinnacle Property.  The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. This property is leased to PinnOak Resources, LLC. In 2006, 2.2 million tons were produced from this property. Metallurgical coal is produced from two underground mines and transported by belt or truck to a preparation plant operated by the lessee. Coal is shipped via the Norfolk Southern railroad to customers such as U.S. Steel, National Steel, and is exported to a number of customers located in Europe.
 
Lone Mountain.  The Lone Mountain property is located in Harlan County, Kentucky. In 2006, 2.5 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 2006, 2.0 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 metallurgical customers such as Algoma Steel and Arcelor.
 
VICC/Kentucky Land.  The VICC/Kentucky Land property is located primarily in Perry, Leslie and Pike Counties, Kentucky. In 2006, 4.0 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.
 
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 Magnum Coal. We acquired this property effective January 1, 2007. Both steam and metallurgical coal are produced 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.


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The map below 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 2006, 3.4 million tons were produced from these properties. We lease this property 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.
 
The map below shows the location of our properties in Southern Appalachia.
 


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Illinois Basin
 
Hocking-Wolford/Cummings.  The Hocking-Wolford property and the Cummings property are both located in Sullivan County, Indiana. In 2006, 1.4 million tons were produced from the properties. Both properties are under common lease to Black Beauty Coal Company, an affiliate of Peabody Energy. Production is currently from a surface mine, and coal is shipped by truck and railroad to customers such as Public Service of Indiana and Indianapolis Power and Light.
 
Sato.  The Sato property is located in Jackson County, Illinois. In 2006, 1.1 million 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.
 
Williamson Development.  The Williamson Development property is located in Franklin and Williamson Counties, Illinois. In mid-2006, we completed the final phase of the acquisition of this property and production began at the mine in the fourth quarter of 2006. In 2006, 66,000 tons were produced from the mine in the initial startup phase. Production is from an underground mine which will eventually use a longwall to produce coal. Production is shipped primarily via CN railroad to customers such as Cinergy. Also, as part of the Cline acquisition we acquired acreage adjacent to the Williamson Development property that will be developed in conjunction with the same mine producing on the Williamson Development property.
 
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 2006, 6.5 million tons were produced from our property. Western Energy Company, a subsidiary 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


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at the mine mouth and by the Burlington Northern Santa Fe railroad to Minnesota Power. A small amount of coal is transported by truck to other customers.
 
The map below shows the location of our properties in Northern Powder River Basin.
 

 
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, 2006, we owned approximately 99% of the reserves in fee. We lease approximately 18.5 million tons, or 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 and Subordinated 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 20, 2007, there were an estimated 23,900 beneficial owners 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, 2005 to December 31, 2006, and the quarterly cash distribution declared and paid with respect to each quarter per common unit.
 
                         
    Price Range     Cash
 
NRP
  High     Low     Distributions  
 
2005
                       
First Quarter
  $ 63.14     $ 48.00     $ 0.6875  
Second Quarter
  $ 61.05     $ 49.00     $ 0.7125  
Third Quarter
  $ 68.95     $ 56.78     $ 0.7375  
Fourth Quarter
  $ 62.70     $ 49.47     $ 0.7625  
2006
                       
First Quarter
  $ 57.16     $ 50.50     $ 0.7900  
Second Quarter
  $ 58.95     $ 51.20     $ 0.8200  
Third Quarter
  $ 59.20     $ 48.20     $ 0.8500  
Fourth Quarter
  $ 59.98     $ 49.50     $ 0.8800  
 
In addition to common units, we have also issued subordinated units that are listed and traded on the NYSE under the symbol “NSP”. As of February 20, 2007, there were an estimated 3,400 beneficial owners of our subordinated units. The computation of the approximate number of unitholders is based upon a broker survey. The subordinated units were issued as part of our initial public offering in October 2002 and receive a quarterly distribution only after sufficient funds have been paid to the common units, as described below. The subordinated units were held privately until August 2005, when a large holder of subordinated units sold 4,200,000 of its subordinated units in a public offering. Subsequently, this unitholder sold the remainder of its subordinated units in several block trades in December 2005.
 
The following table sets forth the high and low sales prices per subordinated unit, as reported on the New York Stock Exchange Composite Transaction Tape from August 10, 2005, the first day of trading, to December 31, 2006, and the quarterly cash distribution declared and paid with respect to each quarter per subordinated unit. In addition to the data in the table, prior to going public, the subordinated units received the same distributions every quarter as the common units.
 
                         
    Price Range     Cash
 
NSP
  High     Low     Distributions  
 
2005
                       
Third Quarter (from August 10, 2005)
  $ 59.20     $ 51.22     $ 0.7375  
Fourth Quarter
  $ 57.95     $ 47.70     $ 0.7625  
2006
                       
First Quarter
  $ 55.40     $ 48.30     $ 0.7900  
Second Quarter
  $ 56.40     $ 48.80     $ 0.8200  
Third Quarter
  $ 56.75     $ 47.56     $ 0.8500  
Fourth Quarter
  $ 58.89     $ 48.40     $ 0.8800  
 
During the subordination period, the holders of our common units are entitled to receive a minimum quarterly distribution of $0.5125 per unit prior to any distribution of available cash to holders of our subordinated units. The


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subordination period is defined generally as the period that will end on the first day of any quarter beginning after September 30, 2007 if (1) we have distributed at least the minimum quarterly distribution on all outstanding units in each of the immediately preceding three consecutive, non-overlapping four-quarter periods and (2) our adjusted operating surplus, as defined in our partnership agreement, during such periods equals or exceeds the amount that would have been sufficient to enable us to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2% general partner interest during those periods. If the subordination period ends, the common units will no longer be entitled to arrearages, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units will be converted into common units.
 
On November 14, 2005, 25% of the subordinated units converted into common units. On November 14, 2006, another 331/3% of the subordinated units outstanding on that date or 25% of the original outstanding subordinated units converted into common units. Providing that the minimum quarterly distribution has been earned and paid to both the common and subordinated units for the preceding 12 quarters, the remaining NSP subordinated units will convert into NRP common units automatically on November 14, 2007. Following the conversion in November 2007, NSP units will no longer exist and all subordinated units will have been converted into NRP units.
 
In connection with the Adena Minerals transaction, we issued 541,956 Class B units to Adena in January 2007. The Class B units are a new class of limited partnership interests in NRP that will be converted to regular common units upon the approval of our unitholders (other than Adena and its affiliates). The Class B Units are subordinate to the regular common units, but senior to the subordinated units, with respect to cash distributions (and in liquidation) and will be entitled to 110% of the cash distributions per common unit if they have not been converted to common units six months following the closing of the transactions contemplated by the Second Contribution Agreement (relating to Cline’s Gatling, Ohio complex) with Adena or September 30, 2008, whichever occurs first. The Class B Units are not listed for trading on the New York Stock Exchange.
 
Our general partner and affiliates of our general partner are entitled 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
 
                             
        Marginal Percentage Interest in
 
        Distributions  
                    Holders of
 
    Total Quarterly
              Incentive
 
    Distribution Target
        General
    Distribution
 
    Amount   Unitholders     Partner     Rights  
 
Minimum Quarterly Distribution
  $0.5125     98 %     2 %      
First Target Distribution
  $0.5125 up to $0.5625     98 %     2 %      
Second Target Distribution
  above $0.5625 up to $0.6625     85 %     2 %     13 %
Third Target Distribution
  above $0.6625 up to $0.7625     75 %     2 %     23 %
Thereafter
  above $0.7625     50 %     2 %     48 %
 
We must distribute all of our cash on hand at the end of each quarter, less 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. 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
 
SELECTED HISTORICAL FINANCIAL DATA
 
The following tables show selected historical financial data for Natural Resource Partners L.P. and our predecessors (Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and the Arch Coal Contributed Properties, collectively known as predecessors), in each case for the periods and as of the dates indicated. We derived the selected historical financial data for Natural Resource Partners L.P. as of December 31, 2006, 2005, 2004, 2003 and 2002, and for the years ended December 31, 2006, 2005, 2004 and 2003 and the period from commencement of operations (October 17, 2002) through December 31, 2002 from the audited financial statements of Natural Resource Partners L.P. We derived the selected historical financial data for the members of the WPP Group (see page 2) for the period from January 1 through October 16, 2002 from the audited financial statements of the WPP Group, and we derived the selected historical financial data for the Arch Coal Contributed Properties for the period from January 1 through October 16, 2002 from the audited financial statements of the Arch Coal Contributed Properties.
 
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.” The tables should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” While substantially all of the producing coal-related assets and operations of the WPP Group were contributed to us, some assets and liabilities were retained by the WPP Group.


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NATURAL RESOURCE PARTNERS L.P.
 
                                         
          From
 
          commencement
 
          of operations
 
          (October 17, 2002)
 
          through
 
    For the years ended December 31,     December 31,  
    2006     2005     2004     2003     2002  
    (In thousands, except per unit and per ton data)  
 
Income Statement Data:
                                       
Revenues:
                                       
Coal royalties
  $ 147,752     $ 142,137     $ 106,456     $ 73,770     $ 11,532  
Aggregate royalties
    538                          
Coal processing fees
    1,452                          
Oil and gas royalties
    4,220       3,180       1,907       1,675        
Property taxes
    5,971       6,516       5,349       5,069       1,047  
Minimums recognized as revenue
    2,082       1,709       1,763       2,033       872  
Override royalties
    957       2,144       3,222       1,022       226  
Other
    7,701       3,367       2,735       1,897       216  
                                         
Total revenues
    170,673       159,053       121,432       85,466       13,893  
Expenses:
                                       
Depreciation, depletion and amortization
    29,695       33,730       30,077       24,483       4,526  
General and administrative
    15,520       12,319       11,503       8,923       1,059  
Property, franchise and other taxes
    8,122       8,142       6,835       5,810       1,296  
Coal royalty and override payments
    1,560       3,392       2,045       1,299       397  
                                         
Total expenses
    54,897       57,583       50,460       40,515       7,278  
                                         
Income from operations
    115,776       101,470       70,972       44,951       6,615  
Interest expense
    (16,423 )     (11,044 )     (11,192 )     (7,696 )     (200 )
Interest income
    2,737       1,413       349       206        
Loss from early extinguishment of debt
                (1,135 )            
Loss on sale of assets
                      (55 )      
Loss from interest rate hedge
                      (499 )      
                                         
Net income
  $ 102,090     $ 91,839     $ 58,994     $ 36,907     $ 6,415  
                                         
Balance Sheet Data (at period end):
                                       
Total assets
  $ 939,493     $ 684,996     $ 599,926     $ 531,676     $ 392,719  
Deferred revenue
    20,654       14,851       15,847       15,054       13,252  
Long-term debt
    454,291       221,950       156,300       192,650       57,500  
Total liabilities
    503,806       259,088       190,734       223,518       74,085  
Partners’ capital
    435,687       425,908       409,192       308,158       318,634  
Cash Flow Data:
                                       
Net cash flow provided by (used in):
                                       
Operating activities
  $ 138,843     $ 121,675     $ 90,847     $ 64,528     $ 6,738  
Investing activities
    (257,714 )     (105,702 )     (77,733 )     (142,511 )     (57,449 )
Financing activities
    137,224       (10,385 )     4,669       94,550       58,463  
Other Data:
                                       
Royalty coal tons produced by lessees
    52,092       53,606       48,357       44,344       7,314  
Average gross coal royalty per ton
  $ 2.84     $ 2.65     $ 2.20     $ 1.66     $ 1.58  
Aggregate tons produced by lessee
    412                          
Average gross aggregate royalty per ton
  $ 1.31                          
Basic and diluted net income per limited partner unit:
                                       
Common
  $ 3.48     $ 3.39     $ 2.29     $ 1.59     $ 0.28  
Subordinated
  $ 3.48     $ 3.39     $ 2.29     $ 1.59     $ 0.28  
Weighted average number of units outstanding:
                                       
Common
    17,183       14,345       13,447       11,354       11,354  
Subordinated
    8,158       10,996       11,354       11,354       11,354  
Distributions per limited partner unit:
                                       
Common
  $ 3.340     $ 2.9000     $ 2.4750     $ 2.1450     $ 0.4234  
Subordinated
  $ 3.340     $ 2.9000     $ 2.4750     $ 2.1450     $ 0.4234  


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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
 
         
    For the
 
    Period From
 
    January 1, through
 
    October 16, 2002(1)  
    (In thousands,
 
    except per ton data)  
 
Income Statement Data:
       
Revenues:
       
Coal royalties
  $ 17,261  
Timber royalties
    2,774  
Gain on sale of property
    92  
Property taxes
    1,221  
Other
    1,219  
         
Total revenues
    22,567  
Expenses:
       
General and administrative
    2,291  
Taxes other than income
    1,438  
Depreciation, depletion and amortization
    3,544  
         
Total expenses
    7,273  
         
Income from operations
    15,294  
Other income (expense):
       
Interest expense
    (4,786 )
Interest income
    114  
Reversionary interest
    (561 )
         
Net income
  $ 10,061  
         
Cash Flow Data:
       
Net cash flow provided by (used in):
       
Operating activities
  $ 8,676  
Investing activities
    (35,028 )
Financing activities
    27,899  
Other Data:
       
Royalty coal tons produced by lessees
    9,572  
Average gross coal royalty per ton
  $ 1.80  
 
 
(1) Up to the date of contribution of assets to Natural Resource Partners L.P.


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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
 
         
    For the
 
    period from
 
    January 1 through
 
    October 16, 2002(1)  
    (In thousands,
 
    except per ton data)  
 
Income Statement Data:
       
Revenues:
       
Coal royalties
  $ 5,895  
Lease and easement income
    474  
Gain on sale of property
     
Property taxes
    61  
Other
    71  
         
Total revenues
    6,501  
Expenses:
       
General and administrative
    417  
Taxes other than income
    69  
Depreciation, depletion and amortization
    1,979  
         
Total expenses
    2,465  
         
Income from operations
    4,036  
Other income (expense):
       
Interest expense
    (1,877 )
Interest income
    115  
         
Net income
  $ 2,274  
         
Cash Flow Data:
       
Net cash flow provided by (used in):
       
Operating activities
  $ 3,725  
Investing activities
     
Financing activities
    (4,069 )
Other Data:
       
Royalty coal tons produced by lessees
    4,970  
Average gross coal royalty per ton
  $ 1.19  
 
 
(1) Up to the date of contribution of assets to Natural Resource Partners L.P.


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NEW GAULEY COAL CORPORATION
 
         
    For the
 
    period from
 
    January 1 through
 
    October 16, 2002(1)  
    (In thousands,
 
    except per ton data)  
 
Income Statement Data:
       
Revenues:
       
Coal royalties
  $ 1,434  
Gain on sale of property
     
Property taxes
    20  
Other
    53  
         
Total revenues
    1,507  
Expenses:
       
General and administrative
    52  
Taxes other than income
    42  
Depreciation, depletion and amortization
    138  
         
Total expenses
    232  
         
Income from operations
    1,275  
Other income (expense):
       
Interest expense
    (97 )
Interest income
    24  
Reversionary interest
    (104 )
         
Net income
  $ 1,098  
         
Cash Flow Data:
       
Net cash flow provided by (used in):
       
Operating activities
  $ 867  
Investing activities
     
Financing activities
    (474 )
Other Data:
       
Royalty coal tons produced by lessees
    479  
Average gross coal royalty per ton
  $ 2.99  
 
 
(1) Up to the date of contribution of assets to Natural Resource Partners L.P.


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ARCH COAL CONTRIBUTED PROPERTIES
 
         
    For the
 
    period from
 
    January 1 through
 
    October 16, 2002(1)  
    (In thousands,
 
    except per ton data)  
 
Income Statement Data:
       
Revenues:
       
Coal royalties
  $ 14,768  
Other royalties
    1,349  
Property taxes
    1,179  
         
Total revenues
    17,296  
Direct costs and expenses:
       
Depletion
    4,889  
Property taxes
    1,179  
Other expense
    528  
         
Total expenses
    6,596  
         
Excess (deficit) of revenues over direct costs and expenses
  $ 10,700  
         
Cash Flow Data:
       
Direct cash flow from contributed properties
  $ 15,181  
Other Data:
       
Royalty coal tons produced by lessees
    8,791  
Average gross coal royalty per ton
  $ 1.68  
 
 
(1) Up to the date of contribution of assets to Natural Resource Partners L.P.


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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 historical financial statements.
 
Executive Overview
 
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. Coal produced from our properties is burned in electric power plants located east of the Mississippi River and in Montana and Minnesota. As of December 31, 2006, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves in eleven states. For the year ended December 31, 2006, approximately 57% of the coal produced from our properties came from underground mines and approximately 43% came from surface mines. As of December 31, 2006, approximately 60% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 36% of our reserves.
 
We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell coal from our reserves in exchange for royalty payments. As of December 31, 2006, our reserves were subject to 180 leases with 70 lessees. For the year ended December 31, 2006, our lessees produced 52.1 million tons of coal generating $147.8 million in coal royalty revenues from our properties and our total revenues were $170.7 million. Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated 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. However, over the long term, our coal royalty revenues are affected by changes in the market price of coal.
 
Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Generally, our lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in those future periods. We do not recognize these minimum coal 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.
 
Coal royalty revenues from our Appalachian properties represented 89% of our total coal royalty revenues for the year ended December 31, 2006, and thus a significant portion of our total revenue is dependent upon Appalachian coal prices. Coal prices are based on supply and demand, specific coal characteristics, economics of alternative fuel, and overall domestic and international economic conditions. Coal prices for both metallurgical and steam coal increased during 2005 and 2006, and as our lessees’ older contracts have rolled over during the last two years, we have received substantially higher royalties from our leases. Our revenue per ton from that region increased to an average of $3.07 per ton for the year ended December 31, 2006 from an average of $2.87 per ton for the same period of 2005. However, because prices have generally stabilized over the last year and our lessees will have fewer contracts that will rollover into substantially higher prices, we expect that our coal royalty revenue per ton will not continue to increase at this pace over the next year. In addition, in spite of the higher prices, most of our lessees have not appreciably increased production due to a number of constraints, including an increase in the cost of mining coal, increased customer stockpiles, a shortage of labor, permitting issues and rail transportation problems. As a result, we believe that a larger percentage of our future revenue growth will come from acquisitions of new reserves.
 
For the year ended December 31, 2006, approximately 33% of our coal royalty revenues and 28% of the related production were from metallurgical coal, which was sold to steel companies in the eastern United States, South America, Europe and Asia. Prices of metallurgical coal have been substantially higher over the last two years, and we expect them to remain at historically high levels in 2007 as well. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and export markets.


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In addition to coal royalty revenues, we generated approximately 14% of our revenues for each of the years ended December 31, 2006 and 2005 from rentals; royalties on oil and gas and coalbed methane leases; timber; overriding royalty arrangements; coal processing fees; and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.
 
We have recently acquired aggregate reserves near DuPont, Washington and coal processing and transportation infrastructure in West Virginia and Illinois. Although neither acquisition contributed materially to our 2006 revenues, we anticipate that both businesses will contribute significant revenues in 2007, and we hope to grow both businesses into meaningful complements to our coal royalty business.
 
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 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,  
    2006     2005     2004  
 
Cash flow from operations
  $ 138,843     $ 121,675     $ 90,847  
Less scheduled principal payments
    (9,350 )     (9,350 )     (9,350 )
Less reserves for future principal payments
    (9,600 )     (9,400 )     (9,400 )
Add reserves used for scheduled principal payments
    9,400       9,400       9,400  
                         
Distributable cash flow
  $ 129,293     $ 112,325     $ 81,497  
                         
 
Acquisitions
 
Recent Acquisitions
 
We are a growth-oriented company and have closed a number of accretive acquisitions over the last several years. Our most recent acquisitions are briefly described below.
 
2007 Acquisitions
 
Dingess-Rum.  On January 16, 2007, we acquired 92 million tons of coal reserves and approximately 33,700 acres of surface and timber in Logan, Clay and Nicholas Counties in West Virginia from Dingess-Rum Properties, Inc. As consideration for the acquisition, we issued 2,400,000 common units to Dingess-Rum.
 
Cline.  On January 4, 2007, we acquired 49 million tons of reserves in Williamson County, Illinois and Mason County, West Virginia that are leased to affiliates of The Cline Group. In addition, we acquired transportation assets and related infrastructure at those mines. As consideration for the transaction we issued 3,913,080 common units and 541,956 Class B units representing limited partner interests in NRP. Through its affiliate Adena Minerals, LLC, The Cline Group received a 22% interest in our general partner and in the incentive distribution rights of NRP in return for providing NRP with the exclusive right to acquire additional reserves, royalty interests and certain transportation infrastructure relating to future mine developments by The Cline Group. Simultaneous with the


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closing of this transaction, we signed a definitive agreement to purchase the coal reserves and transportation infrastructure at Cline’s Gatling Ohio complex. This transaction will close upon commencement of coal production, which is currently expected to occur in 2008. At the time of closing, NRP will issue Adena 2,280,000 additional Class B units, and the general partner of NRP will issue Adena an additional 9% interest in the general partner and the incentive distribution rights.
 
2006 Acquisitions
 
Quadrant.  On December 29, 2006, we acquired an estimated 70 million tons of high quality aggregate reserves located in DuPont, Washington for $23.5 million in cash and assumed a utility local improvement obligation of approximately $3.0 million. Of these reserves, approximately 25 million tons are currently permitted. We will pay an additional $7.5 million when the remaining tons are permitted. If the permit is not obtained by December 2016, the unpermitted tons will revert back to Quadrant. We funded this acquisition with cash and borrowings under our credit facility.
 
Bluestone.  On December 18, 2006, we acquired approximately 20 million tons of low vol metallurgical coal reserves that are located above our Pinnacle reserves in Wyoming County, West Virginia for $20 million. We funded this acquisition with borrowings under our credit facility.
 
D.D. Shepherd.  On December 1, 2006, we acquired nearly 25,000 acres of land containing in excess of 80 million tons of coal reserves for $110 million. The property is located in Boone County, West Virginia adjacent to other NRP property and consists of both metallurgical and steam coal reserves, gas reserves, surface and timber. We funded this acquisition with borrowings under our credit facility.
 
Red Fox.  On September 1, 2006, we acquired the Red Fox preparation plant and coal handling facility located in McDowell County, West Virginia for approximately $8.1 million, of which $4.1 million was paid at closing and the remainder was paid during the third and fourth quarters as construction was completed. This acquisition was the second under our memorandum of understanding with Taggart Global, LLC (formerly Sedgman USA, LLC). The plant will handle an estimated 20 million tons of coal reserves during its life. The initial $4.1 million payment paid at closing was funded through cash and borrowings under our credit facility and the remaining payments were funded with cash.
 
Coal Mountain.  On August 24, 2006, we acquired the Coal Mountain preparation plant, handling facility and rail load-out facility located in Wyoming County, West Virginia for $16.1 million under our memorandum of understanding with Taggart Global. We expect that approximately 35 million tons of coal will be processed through this facility during its life. We paid for the facilities with cash and with borrowings under our credit facility as construction was completed in phases during the third and fourth quarters.
 
Williamson Development.  On January 20, 2006 and August 15, 2006, we closed the second and third phases of the Williamson Development acquisition in Illinois for $35 million each. We funded the January 20, 2006 acquisition with proceeds from the issuance of senior notes and the August 15, 2006 acquisition with borrowings under our credit facility.
 
Allegany County, Maryland.  On June 29, 2006, we acquired 3.3 million tons of coal in Allegany County, Maryland for $5.5 million in cash.
 
Indiana Reserves.  On May 26, 2006, we acquired 16.3 million tons of coal reserves and an overriding royalty interest on an additional 2.4 million tons for $10.85 million in cash. These reserves are located in Pike, Warrick and Gibson Counties in Indiana.
 
Disposition
 
Virginia Timber Properties.  For the year ended December 31, 2006, we received total proceeds of $7.1 million and recorded a total gain of $3.5 million related to transactions involving the sale of timber and related surface acreage located on our property in Wise and Dickenson Counties, Virginia.


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Critical Accounting Policies
 
Coal Royalties.  We recognize coal royalty revenues on the basis of tons of coal 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 coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, we reflect these minimum royalties as deferred revenue, a liability on the balance sheet.
 
Aggregate Royalties.  We recognize aggregate royalty revenues on the basis of tons of aggregate sold by our lessees and the corresponding revenue from those sales. Generally, the aggregate lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of aggregate they sell, subject to a minimum annual payment.
 
Coal Processing Fees.  We recognize coal processing fees 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 lessees are also subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time if sufficient royalties are generated from coal processing in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. The coal processing leases are structured so that the lessees are responsible for operating and maintenance expenses associated with the facilities.
 
Oil and Gas Royalties.  We recognize oil and gas royalties on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on a percentage of the selling price. Some leases are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. We initially record the minimum payments as deferred revenue and recognize them either when the lessee recoups the minimum payments 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 proved 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.
 
Impact of Adoption of FAS 123R
 
We adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payment,” effective January 1, 2006 using the modified prospective approach. Prior to 2006, awards under our Long Term Incentive Plan were accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R 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 the estimated fair value to expense over the service or vesting period of the grant. In addition, FAS 123R requires that we include estimated forfeitures in our 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. FAS 123R required us to recognize the cumulative effect of the accounting change at the date of adoption based on the


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difference between the fair value of the unvested awards and the intrinsic value previously recorded. Included in operating costs and expenses was a one time charge of $661,000 which represents the cumulative effect of adopting FAS 123R as of January 1, 2006. This adjustment had the impact of reducing net income per limited partner unit for the year ended December 31, 2006 by $0.02. Application of FAS 123R to prior periods did not materially impact amounts previously presented.


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Results of Operations
                         
    For the Years Ended
 
    December 31,  
    2006     2005     2004  
    (In thousands, except per ton data)  
Revenues:
                       
Coal royalties
  $ 147,752     $ 142,137     $ 106,456  
Aggregate royalties
    538              
Coal processing fees
    1,452              
Oil and gas royalties
    4,220       3,180       1,907  
Property taxes
    5,971       6,516       5,349  
Minimums recognized as revenue
    2,082       1,709       1,763  
Override royalties
    957       2,144       3,222  
Other
    7,701       3,367       2,735  
                         
Total revenues
    170,673       159,053       121,432  
Expenses:
                       
Depreciation, depletion and amortization
    29,695       33,730       30,077  
General and administrative
    15,520       12,319       11,503  
Property, franchise and other taxes
    8,122       8,142       6,835  
Coal royalty and override payments
    1,560       3,392       2,045  
                         
Total expenses
    54,897       57,583       50,460  
                         
Income from operations
    115,776       101,470       70,972  
Other income (expense):
                       
Interest expense
    (16,423 )     (11,044 )     (11,192 )
Interest income
    2,737       1,413       349  
Loss on early extinguishment of debt
                (1,135 )
                         
Net income
  $ 102,090     $ 91,839     $ 58,994  
                         
Other Data:
                       
Coal Royalties
                       
Appalachia
                       
Northern
  $ 10,231     $ 11,306     $ 7,084  
Central
    100,487       93,008       76,583  
Southern
    20,469       25,089       14,874  
                         
Total Appalachia
    131,187       129,403       98,541  
Illinois Basin
    5,325       4,288       3,852  
Northern Powder River Basin
    11,240       8,446       4,063  
                         
Total
  $ 147,752     $ 142,137     $ 106,456  
                         
Production (tons)
                       
Appalachia
                       
Northern
    5,329       5,977       4,179  
Central
    31,991       32,790       32,702  
Southern
    5,347       6,263       5,208  
                         
Total Appalachia
    42,667       45,030       42,089  
Illinois Basin
    2,877       2,781       3,138  
Northern Powder River Basin
    6,548       5,795       3,130  
                         
Total
    52,092       53,606       48,357  
                         
Average gross royalty
                       
Appalachia
                       
Northern
  $ 1.92     $ 1.89     $ 1.70  
Central
    3.14       2.84       2.34  
Southern
    3.83       4.01       2.86  
                         
Total Appalachia
    3.07       2.87       2.34  
Illinois Basin
    1.85       1.54       1.23  
Northern Powder River Basin
    1.72       1.46       1.30  
                         
Total
  $ 2.84     $ 2.65     $ 2.20  
                         
Aggregate Royalties
                       
Royalty revenues
  $ 538              
Production
    412              
Average gross royalty
  $ 1.33              


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Year ended December 31, 2006 compared with year ended December 31, 2005
 
Revenues.  For the year ended December 31, 2006, total revenues were $170.7 million compared to $159.1 million for the same period in 2005, an increase of $11.6 million or 7%. Coal royalty revenues were $147.8 million on 52.1 million tons of coal produced, compared to $142.1 million in coal royalty revenues on 53.6 million tons of coal produced for the year ended December 31, 2005, representing a 4% increase in coal royalty revenues and a 3% decrease in production. Coal royalty revenues comprised approximately 87% and 89% of our total revenues for each of the years ended December 31, 2006 and 2005.
 
The following is a breakdown of our major coal producing regions:
 
Appalachia.  As a result of higher prices in the Central Appalachia region, coal royalty revenues in Appalachia for the year ended December 31, 2006 were $131.2 million compared to $129.4 million for the same period in 2005, an increase of $1.8 million or 1%. For the year ended December 31, 2006, production in Appalachia was 42.7 million tons compared to 45.0 million tons for the same period in 2005, a decrease of 2.3 million tons or 5%. The Appalachian results by region are set forth below.
 
Northern Appalachia. Coal royalty revenues decreased 10% from $11.3 million for the year ended December 31, 2005 to $10.2 million for the year ended December 31, 2006. Production decreased 12% from 6.0 million tons to 5.3 million tons over the same periods. The property we acquired in June 2006 in Allegany County, Maryland generated coal royalty revenues of $576,000 and production of 222,000 tons. The other significant differences are described below.
 
  •  AFG Properties — production increased from 1.5 million tons to 3.0 million tons and coal royalty revenues increased from $2.7 million to $5.5 million. The increased tonnage was due to a greater proportion of production from the longwall unit being on our property.
 
  •  Sincell — production decreased from 2.6 million tons to 728,000 tons and coal royalty revenues decreased from $4.7 million to $1.2 million. The decreased tonnage was due to a mine exhausting its longwall mineable reserves.
 
  •  Stony River — production decreased from 343,000 tons to 17,000 tons and coal royalty revenues decreased from $851,000 to $55,000 due to the lessee idling production during bankruptcy proceedings.
 
Central Appalachia. Production from our Central Appalachia properties decreased 2% from 32.8 million tons for the year ended December 31, 2005 to 32.0 million tons for the year ended December 31, 2006. However, as a result of higher prices, our coal royalty revenues from these properties increased 8% from $93.0 million to $100.4 million over those same periods. The property we acquired in December 2006 in the D.D. Shepard transaction generated coal royalty revenues of $2.1 million and production of 486,000 tons. In addition to the D.D. Shepard acquisition, the results in Central Appalachia are a combination of increases and decreases over a number of other properties, the most significant of which are described below.
 
  •  VICC/Kentucky Land — production increased from 2.6 million tons to 4.0 million tons and coal royalty revenues increased from $8.8 million to $13.9 million. The increased production was due to an increase in tonnage from mines moving onto the property and production from recently negotiated new leases that more than offset mines moving off the property.
 
  •  VICC/Alpha — production increased from 5.1 million tons to 5.3 million tons and coal royalty revenues increased from $17.2 million to $20.5 million. The tonnage increase was due to slightly improved production from the mines on the property.
 
  •  Plum Creek properties — production increased from 573,000 tons to 1.5 million tons and coal royalty revenues increased from $1.5 million to $4.2 million. The increased production and coal royalty revenues were due primarily to new mines in West Virginia increasing production on the properties over their earlier startup levels.
 
  •  Lynch — production increased from 5.1 million tons to 5.3 million tons and coal royalty revenues increased from $11.5 million to $13.8 million. The tonnage increase was due to a new mine starting on the property.


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  •  Pardee — production increased from 1.7 million tons to 2.0 million tons and coal royalty revenues increased from $6.5 million to $7.7 million. The increased tonnage was due to a greater proportion of production from the mines being on our property.
 
  •  Eunice — production decreased from 2.6 million tons to 738,000 tons and coal royalty revenues decreased from $6.7 million to $2.5 million due to a mine exhausting its longwall mineable reserves and a greater proportion of production from a surface mine coming from adjacent property.
 
  •  Pinnacle — production decreased from 2.9 million tons to 2.2 million tons and coal royalty revenues decreased from $10.8 million to $7.8 million. The decreases were primarily due to coal being produced from adjacent property and slightly lower prices being received by our lessee.
 
  •  Eastern Kentucky Property — production decreased from 552,000 tons to 56,000 tons and coal royalty revenues decreased from $1.9 million to $236,000. The decreased production was due to the lessee temporarily idling the operation during the year. A new lessee resumed production on the property in the fourth quarter of 2006.
 
Southern Appalachia. Our coal royalty revenues in Southern Appalachia decreased 18% from $25.1 million for the year ended December 31, 2005 to $20.5 million for the year ended December 31, 2006, as production decreased 16% from 6.3 million tons to 5.3 million tons over the same period. The following properties contributed to this decrease.
 
  •  Twin Pines/Drummond — production decreased from 685,000 tons to 591,000 tons and coal royalty revenues decreased from $6.1 million to $3.5 million. The decrease in coal royalty revenues was partially due to a temporary royalty reduction in the first half of the year and a lower per ton royalty being paid under the terms of the lease at one mine, as well as a temporary idling of another mine.
 
  •  BLC Properties — production decreased from 3.8 million tons to 3.4 million tons and coal royalty revenues decreased from $12.7 million to $11.9 million. The decrease was due to slightly reduced production and some temporary royalty reduction to one lessee to encourage mining in some areas of difficult geology.
 
  •  Oak Grove — production decreased from 1.7 million tons to 1.3 million tons and coal royalty revenues decreased from $6.2 million to $5.1 million. The decreases were due to lower production from the mine.
 
Illinois Basin.  Production in the Illinois Basin increased 4% from 2.8 million tons for the year ended December 31, 2005 to 2.9 million tons for the year ended December 31, 2006 and coal royalty revenues increased 23% from $4.3 million for the year ended December 31, 2005 to $5.3 million for the year ended December 31, 2006. During the fourth quarter of 2006, production began from a mine on the property we acquired in 2005 and 2006, described formerly as the Steelhead property and now known as the Williamson property. During the fourth quarter, the mine produced 66,000 tons and generated coal royalty revenues of $171,000 in its initial startup phase. The other significant variances are described below.
 
  •  Sato/Trico — production remained nearly constant at 1.4 million tons and coal royalty revenues increased from $2.4 million to $3.0 million. The increase in coal royalty revenues was due to higher sales prices received by our lessee.
 
  •  Hocking Wolford/Cummings — production remained nearly constant at 1.4 million tons and coal royalty revenues increased from $1.9 million to $2.2 million. The increased coal royalty revenues were due to higher sales prices received by our lessee.
 
Northern Powder River Basin.  Production from our Western Energy property increased 0.7 million tons or 12% from 5.8 million tons to 6.5 million tons and coal royalty revenues increased $2.8 million or 33% from $8.4 million to $11.2 million. These increases were due to the typical variations in production resulting from the checkerboard ownership pattern and additional royalty revenues attributable to a positive price adjustment received by a lessee during the third quarter.
 
Other revenues.  Included in other revenues are three related sales of timber and surface acreage located on our property in Wise and Dickenson Counties, Virginia. We received proceeds from the sales of $7.1 million, resulting in a gain of $3.5 million.


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Operating costs and expenses.  For the year ended December 31, 2006, total expenses were $54.9 million, compared to $57.6 million for 2005, representing a decrease of $2.7 million, or 5%. Included in total expenses are:
 
  •  Depletion and amortization of $29.7 million for the year ended December 31, 2006 compared to $33.7 million for the same period in 2005, representing a decrease of $4.0 million. Fluctuations in depletion are dependent on the depletion rates where coal is mined, which can cause total depletion to be lower in periods where production is actually up;
 
  •  General and administrative expenses of $15.5 million for the year ended December 31, 2006, compared to $12.3 million for the year ended December 31, 2005, an increase of $3.2 million, or 26%. The increase in general and administrative expenses is attributable to additional expenses required to manage a larger portfolio of properties as well as an increase in incentive compensation accrual partially attributable to the adoption of FAS 123R. We also had an increase in the allowance for doubtful accounts of $0.8 million during the year ended December 31, 2006;
 
  •  Property, franchise and other taxes were even at $8.1 million for the years ended December 31, 2006 and 2005. Due to acquisitions, property taxes increased about $0.2 million while franchise taxes decreased about the same amount.
 
Interest Expense.  For the year ended December 31, 2006, interest expense was $16.4 million compared to $11.0 million for 2005, an increase of $5.4 million. This increase is attributed to the issuance of senior notes during the third quarter of 2005 and the first quarter of 2006, as well as significantly higher outstanding balances on our credit facility, which was used to fund acquisitions.
 
Year ended December 31, 2005 compared to year ended December 31, 2004
 
Revenues.  For the year ended December 31, 2005, total revenues were $159.1 million compared to $121.4 million for the same period in 2004, an increase of $37.7 million or 31%. Coal royalty revenues were $142.1 million, on 53.6 million tons of coal produced, for the year ending December 31, 2005, and represented 89% of total revenue. For the year ended December 31, 2004, coal royalty revenues were $106.5 million, on 48.4 million tons produced, and represented 87% of total revenue.
 
Coal royalty revenues.  Coal royalty revenues increased to $142.1 million in 2005 from $106.5 million in 2004, an increase of $35.6 million or 33%. Coal production increased to 53.6 million tons from 48.4 million in 2004, an increase of 5.2 million tons or 11%. The substantial increase in coal royalty revenues was primarily due to the significantly higher sales prices realized by our lessees in 2005. In addition, approximately 2.1 million tons and $4.2 million of the increase in coal royalty revenues generated during the year ended December 31, 2005 were attributable to acquisitions we made in 2005. All of these acquisitions were in Appalachia, with the exception of the Williamson Development acquisition, which did not contribute any production or coal royalty revenue until the second half of 2006.
 
The following is a breakdown of our major coal producing regions:
 
Appalachia. Coal royalty revenues in Appalachia in 2005 were $129.4 million compared to $98.5 million in 2004, an increase of $30.9 million, or 31%. In 2005, production in Appalachia was 45.0 million tons compared to 42.1 million tons in 2004, an increase of 2.9 million tons, or 7%. The Appalachia results by region are set forth below.
 
Northern Appalachia. Primarily, as a result of the acquisition of the AFG properties in 2005 and higher prices, our coal royalty revenue increased 59% from $7.1 million for the year ended December 31, 2004 to $11.3 million for the year ended December 31, 2005. Production increased 43% from 4.2 million tons to 6.0 million tons over the same periods. The AFG acquisition generated coal royalty revenue of $2.7 million and production of 1.5 million tons. In addition to the AFG acquisition, the following property was a significant contributor to the variance:
 
  •  Sincell — production increased from 1.6 million tons to 2.6 million tons and coal royalty revenues increased from $2.8 to $4.7 million. The increased tonnage was due to the longwall unit being on our property for a greater portion of the year.


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Central Appalachia. Primarily, due to higher prices, coal royalty revenue increased 21% from $76.6 million for the year ended December 31, 2004 to $93 million for the year ended December 31, 2005, while production only slightly increased from 32.7 million tons to 32.8 million tons for the same periods. The results in Central Appalachia include a combination of increases and decreases over several properties, the most significant of which are described below.
 
In addition to higher coal prices and acquisitions, the properties that had significant increases in production and coal royalty revenues were:
 
  •  Pinnacle — production increased from 1.8 million tons to 2.9 million tons and coal royalty revenues increased from $6.0 million to $10.8 million. The increased tonnage was due to the mine resuming production after being idle for a portion of the year in 2004.
 
  •  Lynch — production increased from 4.5 million tons to 5.1 million tons and coal royalty revenues increased from $8.7 million to $11.5 million. The increased tonnage was due to lessees starting new mines and some mines moving onto the property.
 
  •  VICC/Kentucky Land — production increased from 2.3 million tons to 2.5 million tons and coal royalty revenues increased from $5.5 million to $8.2 million. The increased tonnage was due to a net increase in tonnage from mines moving onto the property that more than offset some mines moving off the property.
 
  •  Eunice — production increased from 2.0 million tons to 2.6 million tons and coal royalty revenues increased from $4.1 million to $6.7 million. The increased tonnage was due to higher production by the longwall unit on the property.
 
  •  Kingston — production increased from 1.1 million tons to 1.7 million tons and coal royalty revenues increased from $2.2 million to $4.6 million. The increased tonnage was due to a new surface mine starting on the property.
 
  •  Pardee — production increased from 1.4 million tons to 1.7 million tons and coal royalty revenues increased from $4.7 million to $6.5 million. The increased tonnage was due to increased production from the surface mines on the property.
 
These increases were partially offset by decreases in production and coal royalty revenues from our West Fork property. Production decreased from 2.7 million tons to nearly zero and coal royalty revenues decreased from $8.0 million to nearly zero as longwall mining was completed on the property.
 
Southern Appalachia. Primarily due to higher prices, coal royalty revenues increased 68% from $14.9 million for the year ended December 31, 2004 to $25.1 million for the year ended December 31, 2005, while production increased from 5.2 million tons to 6.3 million tons for the same periods. The following properties contributed significantly to the variance:
 
  •  BLC — production increased from 3.5 million tons to 3.8 million tons and coal royalty revenues increased from $9.5 million to $12.7 million. The increased tonnage was due to a mine being on our property for a greater portion of the year and improved production at some of the mines on our property.
 
  •  Oak Grove — production increased from 1.4 million tons to 1.7 million tons and coal royalty revenues increased from $3.1 million to $6.2 million. The increased tonnage was due to improved production from the mine.
 
  •  Twin Pines — production increased from 358,000 tons to 572,000 tons and coal royalty revenues increased from $2.2 million to $5.1 million. The increased tonnage was due to the lessee increasing production at the mine.
 
Illinois Basin. Coal royalty revenues increased 11% from $3.9 million for the year ended December 31, 2004 to $4.3 million for the year ended December 31, 2005, while production decreased 11% from 3.1 million tons to 2.8 million tons for the same periods. The property that had an increase in coal royalty revenues is described below:
 
  •  Sato — production increased from 963,000 tons to 1.1 million tons and coal royalty revenues increased from $1.4 million to $1.9 million. The increased tonnage was due to the lessee increasing production at the mine.


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Northern Powder River Basin. Coal royalty revenue increased 105% from $4.1 million to $8.4 million and production increased 87% from 3.1 million tons to 5.8 million tons over the same period. This increase was due to the typical variations in production resulting from the checkerboard ownership pattern and from higher sales prices being received by our lessee. Included in our coal royalty revenues for the year ended December 31, 2004 is a one-time settlement of $170,000, or $0.08 per ton, resulting from an arbitration award our lessee received from a third party.
 
Expenses.  Total expenses were $57.6 million, or 36%, of total revenues for the year ended December 31, 2005, compared to $50.5 million, or 42%, of total revenues for the year ended December 31, 2004.
 
  •  Depreciation, depletion and amortization represented 59% of the total expenses for both 2005 and 2004. Although depreciation, depletion and amortization was the same percentage of revenue for the periods discussed, it can vary depending on where the coal production occurs and fluctuations in depletion rates.
 
  •  General and administrative expenses were approximately 21% and 23% of total expenses for the year ended December 31, 2005 and 2004, excluding accruals for incentive compensation of $3.0 million in 2005 and $3.5 million in 2004. The accruals for incentive compensation decreased as a result of the change in the price of our common units between years.
 
  •  Property, franchise and other taxes were $8.1 million, or 14%, of total expenses for 2005 and $6.8 million, or 13%, of total expenses for 2004. Property and franchise taxes increased due to the acquisitions made during 2005.
 
  •  Coal royalty and override payments were $3.4 million or 6% of total expenses for 2005 and $2.0 million or 4% of total expenses for 2004. The increase in coal royalty and override payments is a direct result of the increase in coal prices.
 
Other Income (Expense).  Interest expense was $11.0 million for 2005 compared with $11.2 million for 2004, a decrease of $0.2 million. This decrease is attributed to lower borrowings under our credit facility and the repayment of a portion of our senior notes during 2005. Interest income increased from 2004 as a result of the investment of surplus cash. Other expense for 2004 includes a one-time charge of $1.1 million for the early extinguishment of debt in connection with our new credit facility.
 
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 $4.0 million in 2006, $3.7 million in 2005 and $3.8 million in 2004. For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement.”
 
The Cline Group
 
On January 4, 2007, we acquired from Adena Minerals, LLC four entities that own approximately 49 million tons of coal reserves in West Virginia and Illinois that are leased to active mining operations, as well as associated transportation and infrastructure assets at those mines. The reserves consist of 37 million tons at Adena’s Gatling mining operation in Mason County, West Virginia and 12 million tons adjacent to reserves currently owned by us at Adena affiliate Williamson Energy’s Pond Creek No. 1 mine in Southern Illinois. In consideration therefor, Adena received 3,913,080 common units and 541,956 Class B units representing limited partner interests in NRP and a 22% interest in our general partner and in our outstanding incentive distribution rights. Adena is an affiliate of The


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Cline Group, a private coal company that controls over 3 billion tons of coal reserves in the Illinois and Northern Appalachian coal basins.
 
Second Contribution Agreement.  At the closing, we executed a Second Contribution Agreement, pursuant to which we agreed to acquire from Adena two entities that own coal reserves in Meigs County, Ohio and associated transportation infrastructure. As consideration, Adena will receive 2,280,000 Class B Units (unless we have received unitholder approval to convert the Class B Units to common units, in which case Adena will receive 2,280,000 common units), as well as an additional 9% interest in the general partner and our outstanding incentive distribution rights. The transactions contemplated by the Second Contribution Agreement are expected to close, subject to customary closing conditions, upon commencement of production of the Ohio coal reserves, which is currently expected to occur in 2008.
 
Restricted Business Contribution Agreement.  As part of the transaction, Christopher Cline, Foresight Reserves LP and Adena (collectively, the “Cline Entities”) and NRP entered into a Restricted Business Contribution Agreement. Pursuant to the terms of the Restricted Business Contribution Agreement, the Cline Entities and their affiliates are obligated to offer to NRP any business owned, operated or invested in by the Cline Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in certain transportation infrastructure relating to future mine developments by the Cline Entities in Illinois. In addition, we created an area of mutual interest (the “AMI”) encompassing the properties to be acquired by us pursuant to the Contribution Agreement and the Second Contribution Agreement. During the applicable term of the Restricted Business Contribution Agreement, the Cline Entities will be obligated to contribute to us any coal reserves held or acquired by the Cline Entities or their affiliates within the AMI. In connection with the offer of any additional mineral properties by the Cline Entities to NRP, the parties to the Restricted Business Contribution Agreement will negotiate and agree upon an area of mutual interest around such minerals, which will supplement and become a part of the AMI.
 
Investor Rights Agreement.  Also at the closing, NRP and certain affiliates and Adena executed an Investor Rights Agreement pursuant to which Adena was granted certain management rights. Specifically, Adena has the right to name two directors (one of which will be independent) to the board of directors of our managing general partner so long as Adena beneficially owns either 5% of our limited partnership interest or 5% of our general partner’s limited partnership interest and so long as certain rights under our managing general partner’s LLC Agreement have not been exercised by Adena or Corbin J. Robertson, Jr. Adena nominated J. Matthew Fifield, Managing Director of Adena, to serve as one of the two directors and anticipates nominating an independent director in the near future. The independent director will be appointed to at least one committee for which such director meets the applicable qualifications. Adena will also have the right, pursuant to the terms of the Investor Rights Agreement, to withhold its consent to the sale or other disposition of any entity or assets contributed by the Cline entities to NRP.
 
Quintana Energy Partners, L.P.
 
In 2006, Corbin J. Robertson, Jr. formed Quintana Energy Partners L.P., or QEP, a private equity fund focused on investments in the energy business. In connection with the formation of QEP, our general partner’s board of directors adopted a conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by QEP. QEP’s governance documents reflect the guidelines set forth in NRP’s conflicts policy. For a more detailed description of this policy, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” in this Form 10-K.
 
In February 2007, QEP acquired a 43% membership interest in Taggart Global, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. NRP currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. NRP 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. In 2006, NRP and Taggart Global jointly developed two such plants in West Virginia.


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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 common and Class B units. We believe that cash generated from our operations, combined with the availability under our credit facility and the proceeds from the issuance of debt and equity, will be sufficient to fund working capital, capital expenditures and future acquisitions. Our ability to satisfy any debt service obligations, fund planned capital expenditures, make acquisitions and pay distributions to our unitholders will depend upon our ability to access the capital markets, as well as our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business 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 our operations, please read “Item 1A. Risk Factors.” Our capital expenditures, other than for acquisitions, have historically been minimal.
 
Net cash provided by operations for the years ended December 31, 2006, 2005 and 2004 was $138.8 million, $121.7 million and $90.8 million, respectively. Substantially all of our cash provided by operations since inception has been generated from coal royalty revenues.
 
Net cash used in investing activities for the years December 31, 2006, 2005 and 2004 was $257.7 million, $105.7 million and $77.7 million, respectively. In each of those years, substantially all of our investing activities consisted of acquiring coal reserves and other mineral rights. In the third quarter of 2005, we also acquired a coal preparation plant and rail loadout facility for $6 million and in the third quarter of 2006, we acquired two more coal preparation plants and related handling facilities totaling $24.2 million. In December 2006, we acquired aggregate reserves for $23.5 million. In 2006, we sold non-core timberlands for gross proceeds totaling $7.1 million.
 
Net cash generated from financing activities for the years ended December 31, 2006 and 2005 was $137.2 million and $4.7 million, respectively, while we used $10.4 million in cash for financing activities for the year ended December 31, 2005. All of the loan proceeds from our credit facility were used to fund our acquisitions. We issued $50 million in senior notes in each of 2006 and 2005 and used those proceeds to pay down our credit facility. We also made $9.35 million in principal payments on our senior notes in each of the three year periods. In 2004, we used $100.1 million of the proceeds from the sale of 5.25 million of our common units to redeem 2.6 million common units held by Arch Coal, and we used the balance of the proceeds, or $102.5 million, to pay down our credit facility. We also paid cash distributions to our partners totaling $92.4 million, $75.2 million and $60.4 million for each of the years ending December 31, 2006, 2005 and 2004, respectively.
 
Contractual Obligations and Commercial Commitments
 
At December 31, 2006, our debt consisted of:
 
  •  $214 million outstanding under our $300 million revolving credit facility that matures in October 2010;
 
  •  $35 million of 5.55% senior notes due 2013;
 
  •  $61.85 million of 4.91% senior notes due 2018;
 
  •  $100 million of 5.05% senior notes due 2020;
 
  •  $2.9 million of a 5.31% utility local improvement obligation due 2021; and
 
  •  $50.1 million of 5.55% senior notes due 2023.
 
In December 2006, we increased the limit under our credit facility to $300 million pursuant to the accordion feature in the credit agreement. We may prepay all loans at any time without penalty. Indebtedness under the our credit facility bears interest, at our option, at either:
 
  •  the higher of the federal funds rate plus an applicable margin ranging from 0% to 1.00% or the prime rate as announced by the agent bank; or


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  •  at a rate equal to LIBOR plus an applicable margin ranging from .75% to 2.00%.
 
We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.15% to 0.40% per annum.
 
Our credit facility 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.  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 note purchase agreement contains covenants requiring our operating subsidiary to:
 
  •  not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and
 
  •  maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.
 
The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2006 (in millions):
 
                                                         
    Payments Due by Period(1)  
Contractual Obligations
  Total     2007     2008     2009     2010     2011     Thereafter  
 
Long-term debt (including current maturities)
  $ 556.10     $ 22.26     $ 29.47     $ 28.59     $ 241.70     $ 26.83     $ 207.25  
                                                         
 
 
(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 also includes the $214 million outstanding principal balance at December 31, 2006 under our credit facility, which matures in October 2010.
 
Shelf Registration
 
On December 23, 2003, we and our operating subsidiaries jointly filed a $500 million “universal shelf” registration statement with the Securities and Exchange Commission for the proposed sale of debt and equity securities. Securities issued under this registration statement may be in the form of common units representing limited partner interests in Natural Resource Partners or debt securities of NRP or any of our operating subsidiaries. The registration statement also covers, for possible future sales, up to 673,715 common units held by Great Northern Properties Limited Partnership. In November 2004, Great Northern Properties sold 300,000 common units in a private placement.
 
Approximately $290.2 million is available under our shelf registration statement. The securities may be offered from time to time directly or through underwriters at amounts, prices, interest rates and other terms to be determined at the time of any offering. The net proceeds from the sale of securities from the shelf will be used for future acquisitions and other general corporate purposes, including the retirement of existing debt. We did not and will not receive any proceeds from the sale of common units by Great Northern Properties.


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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, 2006, 2005 and 2004.
 
Environmental
 
The operations our lessees conduct on our properties are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As an owner of surface interests in some properties, we may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of our coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify us against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because we have no employees, employees of Western Pocahontas Properties Limited Partnership make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. We believe that our lessees will be able to comply with existing regulations and do not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on our financial condition or results of operations. We have neither incurred, nor are aware of, any material environmental charges imposed on us related to our properties for the period ended December 31, 2006. 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 our lessees’ reclamation obligations.
 
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 efficient 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. In previous years, a large portion of these sales were under long-term contracts. We estimate that 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 intends to monitor interest rates and may enter into interest rate instruments to protect against increased borrowing costs. At December 31, 2006, we had $214 million outstanding in variable interest debt. If interest rates were to increase by 1%, annual interest expense would increase $2.1 million, assuming the same principal amount remained outstanding during the year.


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Item 8.   Financial Statements and Supplementary Data
 
INDEX TO FINANCIAL STATEMENTS
 
         
    Page
 
  50
  51
  52
  53
  54
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NATURAL RESOURCE PARTNERS L.P.
 
CONSOLDATED FINANCIAL STATEMENTS
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Partners of Natural Resource Partners L.P.
 
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2006 and 2005, and the related consolidated statements of income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, Natural Resource Partners L.P. adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payment”.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2006, 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 27, 2007 expressed an unqualified opinion thereon.
 
Ernst & Young LLP
 
Houston, Texas
February 27, 2007


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NATURAL RESOURCE PARTNERS L.P.
 
CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,
    December 31,
 
    2006     2005  
    (In thousands, except
 
    for unit information)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 66,044     $ 47,691  
Accounts receivable, net of allowance for doubtful accounts
    23,357       21,946  
Accounts receivable — affiliate
    21       6  
Other
    1,411       833  
                 
Total current assets
    90,833       70,476  
Land
    17,781       14,123  
Plant and equipment, net
    29,615       5,924  
Coal and other mineral rights, net
    798,135       590,459  
Loan financing costs, net
    2,197       2,431  
Other assets, net
    932       1,583  
                 
Total assets
  $ 939,493     $ 684,996  
                 
 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 1,041     $ 677  
Accounts payable — affiliate
    105       88  
Current portion of long-term debt
    9,542       9,350  
Accrued incentive plan expenses — current portion
    5,418       1,105  
Property, franchise and other taxes payable
    4,330       4,138  
Accrued interest
    3,846       1,534  
                 
Total current liabilities
    24,282       16,892  
Deferred revenue
    20,654       14,851  
Accrued incentive plan expenses
    4,579       5,395  
Long-term debt
    454,291       221,950  
Partners’ capital:
               
Common units (outstanding: 19,663,715 in 2006, 16,825,307 in 2005)
    338,912       292,990  
Subordinated units (outstanding: 5,676,817 in 2006, 8,515,228 in 2005)
    83,772       123,114  
General partner’s interest
    12,138       10,024  
Holders of incentive distribution rights
    1,616       582  
Accumulated other comprehensive loss
    (751 )     (802 )
                 
Total partners’ capital
    435,687       425,908  
                 
Total liabilities and partners’ capital
  $ 939,493     $ 684,996  
                 
 
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,  
    2006     2005     2004  
    (In thousands, except per unit data)  
 
Revenues:
                       
Coal royalties
  $ 147,752     $ 142,137     $ 106,456  
Aggregate royalties
    538              
Coal processing fees
    1,452              
Oil and gas royalties
    4,220       3,180       1,907  
Property taxes
    5,971       6,516       5,349  
Minimums recognized as revenue
    2,082       1,709       1,763  
Override royalties
    957       2,144       3,222  
Other
    7,701       3,367       2,735  
                         
Total revenues
    170,673       159,053       121,432  
Operating costs and expenses:
                       
Depreciation, depletion and amortization
    29,695       33,730       30,077  
General and administrative
    15,520       12,319       11,503  
Property, franchise and other taxes
    8,122       8,142       6,835  
Coal royalty and override payments
    1,560       3,392       2,045  
                         
Total operating costs and expenses
    54,897       57,583       50,460  
                         
Income from operations
    115,776       101,470       70,972  
Other income (expense)
                       
Interest expense
    (16,423 )     (11,044 )     (11,192 )
Interest income
    2,737       1,413       349  
Loss on early extinguishment of debt
                (1,135 )
                         
Net income
  $ 102,090     $ 91,839     $ 58,994  
                         
Net income attributable to:(1)
                       
General partner
  $ 9,717     $ 4,491     $ 1,705  
                         
Holders of incentive distribution rights
  $ 4,133     $ 1,429     $ 281  
                         
Limited partners
  $ 88,240     $ 85,919     $ 57,008  
                         
Basic and diluted net income per limited partner unit:
                       
Common
  $ 3.48     $ 3.39     $ 2.29  
                         
Subordinated
  $ 3.48     $ 3.39     $ 2.29  
                         
Weighted average number of units outstanding:
                       
Common
    17,183       14,345       13,447  
                         
Subordinated
    8,158       10,996       11,354  
                         
 
 
(1) Net Income is allocated among the limited partners, the general partner and holders of the incentive distribution rights (IDRs) based upon their pro rata share of distributions. The IDRs are allocated 65% to the general partner and the remaining 35% to affiliates of the general partner. The IDRs allocated to the general partner are included in the net income attributable to the general partner.
 
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     Subordinated Units     Partner
    Rights
    Comprehensive
       
    Units     Amounts     Units     Amounts     Amounts     Amounts     Income (Loss)     Total  
    (In thousands, except unit data)  
 
Balance at December 31, 2003
    11,353,658     $ 143,956       11,353,658     $ 158,633     $ 6,474     $     $ (905 )   $ 308,158  
Issuance of units to the public, net of offering and other costs
    5,250,000       200,355                                     200,355  
Redemption of common units, net
    (2,616,752 )     (100,121 )                                   (100,121 )
Additional contribution by the General Partner
                            2,147                   2,147  
Distributions to unitholders
          (31,730 )           (26,963 )     (1,524 )     (176 )           (60,393 )
Net income for the year ended December 31, 2004
          31,354             25,654       1,705       281             58,994  
Loss on interest hedge
                                        52       52  
                                                                 
Comprehensive income
                                        52       59,046  
                                                                 
Balance at December 31, 2004
    13,986,906     $ 243,814       11,353,658     $ 157,324     $ 8,802     $ 105     $ (853 )   $ 409,192  
                                                                 
Subordinated units converted to common
    2,838,430       39,873       (2,838,430 )     (39,873 )                        
Redemption of fractional units upon conversion of subordinated units
    (29 )     (1 )                                   (1 )
Distributions to unitholders
          (39,162 )           (31,790 )     (3,269 )     (952 )           (75,173 )
Net income for the year ended December 31, 2005
          48,466             37,453       4,491       1,429             91,839  
Loss on interest hedge
                                        51       51  
                                                                 
Comprehensive income
                                        51       91,890  
                                                                 
Balance at December 31, 2005
    16,825,307     $ 292,990       8,515,228     $ 123,114     $ 10,024     $ 582     $ (802 )   $ 425,908  
                                                                 
Subordinated units converted to common
    2,838,411       40,775       (2,838,411 )     (40,775 )                        
Redemption of fractional units upon conversion of subordinated units
    (3 )                                          
Distributions to unitholders
          (54,220 )           (27,440 )     (7,603 )     (3,099 )           (92,362 )
Net income for the year ended December 31, 2006
          59,367             28,873       9,717       4,133             102,090  
Loss on interest hedge
                                        51       51  
                                                                 
Comprehensive income
                                        51       102,141  
                                                                 
Balance at December 31, 2006
    19,663,715     $ 338,912       5,676,817     $ 83,772     $ 12,138     $ 1,616     $ (751 )   $ 435,687  
                                                                 
 
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,  
    2006     2005     2004  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income
  $ 102,090     $ 91,839     $ 58,994  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    29,695       33,730       30,077  
Non-cash interest charge
    349       318       932  
Loss on early extinguishment of debt
                1,135  
Gain on sale of timber assets
    (3,471 )            
Change in operating assets and liabilities:
                       
Accounts receivable
    (1,426 )     (6,869 )     (4,093 )
Other assets
    (579 )     (47 )     236  
Accounts payable and accrued liabilities
    381       84       (47 )
Accrued interest
    2,312       1,268       (415 )
Deferred revenue
    5,803       (996 )     793  
Accrued incentive plan expenses
    3,497       1,670       2,574  
Property, franchise and other taxes payable
    192       678       661  
                         
Net cash provided by operating activities
    138,843       121,675       90,847  
                         
Cash flows from investing activities:
                       
Acquisition of land, plant and equipment, coal and other mineral rights
    (264,765 )     (105,702 )     (77,733 )
Proceeds from sale of timber assets
    7,051              
                         
Net cash used in investing activities
    (257,714 )     (105,702 )     (77,733 )
                         
Cash flows from financing activities:
                       
Proceeds from loans
    254,000       125,000       75,500  
Deferred financing costs
    (64 )     (861 )     (969 )
Repayment of loans
    (24,350 )     (59,350 )     (111,850 )
Distributions to partners
    (92,362 )     (75,173 )     (60,393 )
Contributions by general partner
                2,147  
Proceeds from sale of 5,250,000 common units, net of transaction costs
                200,355  
Redemption of 2,616,752 common units, net
                (100,121 )
Redemption of fractional units upon conversion of subordinated units
          (1 )      
                         
Net cash (used in) provided by financing activities
    137,224       (10,385 )     4,669  
                         
Net increase in cash
    18,353       5,588       17,783  
Cash at beginning of period
    47,691       42,103       24,320  
                         
Cash at end of period
  $ 66,044     $ 47,691     $ 42,103  
                         
Supplemental cash flow information:
                       
Cash paid during the period for interest
  $ 13,734     $ 9,459     $ 10,603  
                         
Non-cash financing activities:
                       
Utility improvement obligation acquired
  $ 2,883              
                         
 
The accompanying notes are an integral part of these financial statements.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.   Basis of Presentation and Organization
 
Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning and managing 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, 2006, the Partnership owned or controlled approximately 2.1 billion tons of proven and probable coal reserves (unaudited) in eleven states. 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.
 
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 seven of the directors, four of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC.
 
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.
 
Reclassification
 
Certain reclassifications have been made to the prior year’s financial statements to conform to current year classifications.
 
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.
 
Cash Equivalents
 
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.
 
Accounts Receivable
 
Accounts receivable 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


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. 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 which consists of coal preparation plants and rail loadout facilities are recorded at cost and are being depreciated on a straight-line basis over their useful life.
 
Asset Impairment
 
If facts and circumstances suggest that a long-lived 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.
 
Concentration of Credit Risk
 
Substantially all of the Partnership’s accounts receivable result from amounts due from third-party companies in the coal industry. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be affected by changes in economic or other conditions. Receivables are generally not collateralized.
 
Fair Value of Financial Instruments
 
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 current assets and current liabilities approximates their fair value due to their short-term nature. The fair market value of the Partnership’s long-term debt was estimated to be $235.4 million and $197.6 million at December 31, 2006 and 2005, respectively, for the senior notes. The fair values of the senior notes represent management’s best estimate based on other financial instruments with similar characteristics.
 
Since the Partnership’s credit facility has variable rate debt, its fair value approximates its carrying amount. The Partnership had $214.0 million in outstanding debt under the credit facility at December 31, 2006.
 
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 Royalties.  Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the coal lessees make payments to the


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
 
Aggregate Royalties.  Aggregate royalty revenues are recognized on the basis of tons of aggregate sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the aggregate 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 aggregate they sell, subject to a minimum annual payment.
 
Coal Processing 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 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 lessees are also subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time if sufficient royalties are generated from coal processing in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. The coal processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities.
 
Minimum Royalties.  Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty 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.
 
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. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue when received and recognized as revenue either when the lessee recoups the minimum payments 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. The lessees are typically 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 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 the 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 adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payment,” effective January 1, 2006 using the modified prospective approach. Prior to 2006, awards under our Long Term Incentive Plan were accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R provides


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

that grants must be accounted for using the fair value method, which requires us to estimate the fair value of the grant and charge the estimated fair value to expense over the service or vesting period of the grant. In addition, FAS 123R requires that we include estimated forfeitures in our 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. FAS 123R required us to recognize the cumulative effect of the accounting change at the date of adoption based on the difference between the fair value of the unvested awards and the intrinsic value previously recorded. Included in operating costs and expenses was a one time charge of $661,000 which represents the cumulative effect of adopting FAS 123R as of January 1, 2006. This adjustment had the impact of reducing net income per limited partner unit for the year ended December 31, 2006 by $0.02. Application of FAS 123R to prior periods did not materially impact amounts previously presented.
 
3.   Allowance for Doubtful Accounts
 
Activity in the allowance for doubtful accounts for the years ended December 31, 2006, 2005 and 2004 was as follows:
 
                         
    2006     2005     2004  
    (In thousands)  
 
Balance, January 1
  $ 85     $ 185     $ 306  
Provision charged to operations:
                       
Accounts charged off
    822       30        
Recovery of prior charge offs
    (1 )     (130 )     (121 )
                         
Balance, December 31
  $ 906     $ 85     $ 185  
                         
 
4.   Plant and Equipment
 
The Partnership’s plant and equipment consist of the following:
 
                 
    December 31,
    December 31,
 
    2006     2005  
    (In thousands)  
 
Plant and equipment at cost
  $ 30,266     $ 6,019  
Less accumulated depreciation
    (651 )     (95 )
                 
Net book value
  $ 29,615     $ 5,924  
                 
 
                         
    For the Years Ended
 
    December 31,  
    2006     2005     2004  
    (In thousands)  
 
Total depreciation expense on plant and equipment
  $ 556     $ 95     $  
                         
 
5.   Coal and Other Mineral Rights
 
The Partnership’s coal and other mineral rights consist of the following:
 
                 
    December 31,
    December 31,
 
    2006     2005  
    (In thousands)  
 
Coal and other mineral rights
  $ 970,342     $ 734,242  
Less accumulated depletion and amortization
    (172,207 )     (143,783 )
                 
Net book value
  $ 798,135     $ 590,459  
                 


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                         
    For the Years Ended
 
    December 31,  
    2006     2005     2004  
    (In thousands)  
 
Total depletion and amortization expense on coal and other mineral interests
  $ 28,487     $ 32,667     $ 29,093  
                         
 
6.   Long-Term Debt
 
Long-term debt consists of the following:
 
                 
    December 31,
    December 31,
 
    2006     2005  
    (In thousands)  
 
$300 million floating rate revolving credit facility, due October 2010
  $ 214,000     $ 25,000  
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023
    50,100       53,400  
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018
    61,850       67,900  
5.55% senior notes, with semi-annual interest payments in June and December, maturing June 2013
    35,000       35,000  
5.05% senior notes, with semi-annual interest payments in January and July, with scheduled principal payments beginning July 2008, maturing in July 2020
    100,000       50,000  
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021
    2,883        
                 
Total debt
    463,833       231,300  
Less — current portion of long term debt
    (9,542 )     (9,350 )
                 
Long-term debt
  $ 454,291     $ 221,950  
                 
 
Principal payments due in:
 
         
2007
  $ 9,542  
2008
    17,234  
2009
    17,234  
2010
    231,234  
2011
    17,234  
Thereafter
    171,355  
         
    $ 463,833  
         
 
Indebtedness under the revolving credit facility bears interest, at the Partnership’s option, at either:
 
  •  the higher of the federal funds rate plus an applicable margin ranging from 0.00% to 1.00% or the prime rate as announced by the agent bank; or
 
  •  at a rate equal to LIBOR plus an applicable margin ranging from 0.75% to 2.00%.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
At December 31, 2006, the weighted average interest rate on the outstanding advances was 6.53%. The Partnership incurs a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.15% to 0.40% per annum.
 
The credit facility agreement also 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 the Partnership has 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 also has outstanding $246.9 million in unsecured senior notes which are guaranteed by its operating subsidiaries. Proceeds from the issuance of the senior notes were used to repay borrowings under the Partnership’s revolving credit facility and for related expenses. The terms under the senior notes among other things require that the Partnership maintain a fixed charge coverage ratio of not less than 3.50 to 1.0 and a limit on consolidated debt to consolidated EBITDA of not more than 4.0 to 1. 0, as defined in the credit agreement.
 
The Partnership was in compliance with all terms under its long-term debt as of December 31, 2006.
 
As a result of an acquisition of aggregate reserves, the Partnership assumed a utility local improvement obligation of $2.9 million bearing an interest rate of 5.31%, payable annually and maturing March 2021.
 
7.   Net Income Per Unit Attributable to Limited Partners
 
Net income per unit attributable to limited partners is based on the weighted-average number of common and subordinated units outstanding during the period and is allocated in the same ratio as quarterly cash distributions are made. Net income per unit attributable to limited partners is computed by dividing net income attributable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. Basic and diluted net income per unit attributable to limited partners are the same since the Partnership has no potentially dilutive securities outstanding.
 
8.   Related Party Transactions
 
Quintana Minerals Corporation, a company controlled by Corbin J. Robertson, Jr., Chairman and CEO of GP Natural Resource Partners LLC, provided certain administrative services to the Partnership and charged it for direct costs related to the administrative services. Total expenses charged to the Partnership under this arrangement were $0.8 million, $0.8 million, and $1.1 million for the years ending December 31, 2006, 2005 and 2004, respectively. These costs are reflected in general and administrative expenses in the accompanying statements of income. At December 31, 2006 and 2005, the Partnership also had accounts payable to affiliates of $0.1 million, which includes general and administrative expense payable to Quintana Minerals Corporation.
 
Western Pocahontas Properties, a limited partnership whose general partner is also controlled by Corbin J. Robertson, Jr., Chairman and CEO of G.P. Natural Resource Partners LLC, provides certain administrative services for the Partnership. Total expenses charged to the Partnership under this arrangement were $3.2 million, $2.6 million, and $2.7 million for the years ending December 31, 2006, 2005 and 2004, respectfully. These costs are reflected in general and administrative expenses in the accompanying statements of income.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
9.   Commitments and Contingencies
 
Legal
 
The Partnership is involved, from time to time, in various other legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, the Partnership’s management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.
 
Environmental Compliance
 
The operations conducted on the Partnership’s properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the period ended December 31, 2006. The Partnership is not associated with any environmental contamination that may require remediation costs.
 
10.   Major Lessees
 
The Partnership has one lessee that generated in excess of ten percent of total revenues for 2006. Revenues from major lessees that exceeded 10% of total revenues in any one of the last three years are as follows:
 
                                                 
    For the Years Ended December 31,  
    2006     2005     2004  
    (Dollars in thousands)  
    Revenues     Percent     Revenues     Percent     Revenues     Percent  
 
Lessee A
  $ 15,527       9.0%     $ 18,220       11.5%     $ 13,770       11.3%  
Lessee B
  $ 23,146       13.5%     $ 19,966       12.6%     $ 18,705       15.4%  
Lessee C
  $ 12,883       7.5%     $ 17,056       10.7%     $ 9,146       7.5%  
 
11.   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, the phantom units of a grantee will receive the market value of a common unit in cash upon vesting. Market value is determined by taking the average closing price over the last 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


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.
 
A summary of activity in the outstanding grants of phantom units for the year ended December 31, 2006 are as follows:
 
         
Outstanding grants at the beginning of the period
    211,931  
Grants during the period
    61,166  
Grants vested and paid during the period
    (13,947 )
Forfeitures during the period
    (1,540 )
         
Outstanding grants at the end of the period
    257,610  
         
 
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 volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 4.92% to 4.61% and 22.14% to 25.77%, respectively at December 31, 2006. The Partnership’s historic dividend rate of 5.85% was used in the calculation at December 31, 2006. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $4.3 million, $3.0 million and $3.5 million for the years ended December 31, 2006, 2005 and 2004 respectively, including $661,000 in the first quarter of 2006 related to the cumulative effect of the change in accounting method discussed above. In connection with the Long-Term Incentive Plans, cash payments of $0.8 million, $1.3 million and $0.9 million were paid during each of the years ended December 31, 2006, 2005 and 2004. The unaccrued cost associated with the outstanding grants at December 31, 2006 was $5.7 million.
 
12.   Subsequent Events (Unaudited)
 
Acquisitions
 
Cline.  On January 4, 2007, the Partnership acquired 49 million tons of reserves in Williamson County, Illinois and Mason County, West Virginia that are leased to affiliates of The Cline Group. In addition, the Partnership acquired transportation assets and related infrastructure at those locations. As consideration for the transaction the Partnership issued 3,913,080 common units and 541,956 Class B units representing limited partner interests in NRP. Through its affiliate Adena Minerals, LLC, The Cline Group also received a 22% interest in the Partnership’s general partner and in the incentive distribution rights of NRP in return for providing NRP with the exclusive right to acquire additional reserves, royalty interests and certain transportation infrastructure relating to future mine developments by The Cline Group. Simultaneous with the closing of this transaction, the Partnership signed a definitive agreement to purchase the reserves and transportation infrastructure at Cline’s Gatling Ohio complex. This transaction will close upon commencement of coal production, which is currently expected to occur in 2008. At the time of closing, NRP will issue Adena 2,280,000 additional Class B units, and the general partner of NRP will issue Adena an additional 9% interest in the general partner and the incentive distribution rights.
 
Dingess-Rum.  On January 16, 2007, the Partnership acquired 92 million tons of coal reserves and approximately 33,700 acres of surface and timber in Logan, Clay and Nicholas Counties in West Virginia from Dingess-Rum Properties, Inc. As consideration for the acquisition, the Partnership issued 2,400,000 common units to Dingess-Rum.
 
Distributions
 
On February 14, 2007, the Partnership paid a quarterly distribution of $0.88 per unit to all holders of common, Class B and subordinated units.


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NATURAL RESOURCE PARTNERS L.P.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13.   Supplemental Financial Data
 
Selected Quarterly Financial Information
(Unaudited)
 
                                 
    First
    Second
    Third
    Fourth
 
2006
  Quarter     Quarter     Quarter     Quarter  
    (In thousands, except per unit data)  
 
Total revenues
  $ 46,528     $ 40,982     $ 41,491     $ 41,672  
Income from operations
    31,624       27,964       28,569       27,619  
Net income
  $ 28,524     $ 25,044     $ 25,274     $ 23,248  
Basic and diluted net income per limited partner unit:
                               
Common
  $ 1.01     $ 0.86     $ 0.85     $ 0.76  
Subordinated
  $ 1.01     $ 0.86     $ 0.85     $ 0.76  
Weighted average number of units outstanding, Basic and diluted:
                               
Common
    16,825       16,825       16,825       18,245  
Subordinated
    8,515       8,515       8,515       7,096  
 
                                 
    First
    Second
    Third
    Fourth
 
2005
  Quarter     Quarter     Quarter     Quarter  
 
Total revenues
  $ 36,247     $ 41,697     $ 38,735     $ 42,374  
Income from operations
    22,673       27,211       23,962       27,624  
Net income
  $ 20,447     $ 24,972     $ 21,465     $ 24,955  
Basic and diluted net income per limited partner unit:
                               
Common
  $ 0.77     $ 0.92     $ 0.79     $ 0.91  
Subordinated
  $ 0.77     $ 0.92     $ 0.79     $ 0.91  
Weighted average number of units outstanding, Basic and diluted:
                               
Common
    13,987       13,987       13,987       15,407  
Subordinated
    11,354       11,354       11,354       9,934  
 
                                 
    First
    Second
    Third
    Fourth
 
2004
  Quarter     Quarter     Quarter     Quarter  
 
Total revenues
  $ 26,362     $ 29,497     $ 34,221     $ 31,352  
Income from operations
    14,537       17,751       21,984       16,700  
Net income
  $ 11,174     $ 15,128     $ 19,368     $ 13,324  
Basic and diluted net income per limited partner unit:
                               
Common
  $ 0.47     $ 0.58     $ 0.74     $ 0.50  
Subordinated
  $ 0.47     $ 0.58     $ 0.74     $ 0.50  
Weighted average number of units outstanding, Basic and diluted:
                               
Common
    11,816       13,987       13,987       13,987  
Subordinated
    11,354       11,354       11,354       11,354  


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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, 2006. 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 disclosure.
 
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 our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2006 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, 2006. 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.
 
Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included below in this Item 9A.
 
Attestation Report of Independent Registered Public Accounting Firm
 
The Partners of Natural Resource Partners L.P.
 
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Natural Resource Partners L.P. maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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


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includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, management’s assessment that Natural Resource Partners L.P. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the related consolidated statements of income, partners’ capital equity, and cash flows for each of the three years in the period ended December 31, 2006 and our report dated February 27, 2007, expressed an unqualified opinion thereon.
 
Ernst & Young LLP
 
Houston, Texas
February 27, 2007
 
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 our managing general partner, GP Natural Resource Partners LLC, for its services. All directors are elected by the sole member of our managing general partner, subject to Adena’s rights under the Investor Rights Agreement; and all officers are elected by our managing general partner. 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 have served as officers or directors of the partnership since the initial public offering.
 
             
Name
  Age    
Position with the Managing General Partner
 
Corbin J. Robertson, Jr. 
    59     Chairman of the Board and Chief Executive Officer
Nick Carter
    60     President and Chief Operating Officer
Dwight L. Dunlap
    53     Chief Financial Officer and Treasurer
Kevin F. Wall
    50     Vice President and Chief Engineer
Kathy E. Hager
    55     Vice President Investor Relations
Wyatt L. Hogan
    35     Vice President, General Counsel and Secretary
Kevin J. Craig
    38     Vice President, Business Development
Kenneth Hudson
    52     Controller
Robert T. Blakely
    65     Director
David M. Carmichael
    68     Director
J. Matthew Fifield
    33     Director
Robert B. Karn III
    65     Director
S. Reed Morian
    60     Director
W. W. Scott, Jr. 
    61     Director
Stephen P. Smith
    45     Director
 
Corbin J. Robertson, Jr. is the Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson 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 and 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 Energy Partners L.P., Chairman of the Board of Quintana Maritime Limited and the Cullen Trust for Higher Education and on the boards of the American Petroleum Institute, the National Petroleum Council, the Baylor Collage of Medicine and the World Health and Golf Association.
 
Nick Carter is the President and Chief Operating Officer of GP Natural Resource Partners LLC. 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.
 
Dwight L. Dunlap is the Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC. 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.


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Kevin F. Wall is Vice President and Chief Engineer of GP Natural Resource Partners LLC. Mr. Wall has served as Vice President — Engineering for 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 and is a past president of the West Virginia Society of Professional Engineers.
 
Kathy E. Hager is Vice President — Investor Relations of GP Natural Resource Partners LLC. Ms. Hager 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. Hager has served on the local board of directors of the National Investor Relations Institute and has maintained professional affiliations with various energy industry organizations. She has also served on the Executive Committee and as a National Vice President of the Institute of Management Accountants.
 
Wyatt L. Hogan is Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC. 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. 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.
 
Kevin J. Craig is the Vice President of Business Development for GP Natural Resource Partners LLC. Mr. Craig joined the partnership 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 and 2006. Prior to joining CSX, he served as a Captain in the United States Army.
 
Kenneth Hudson is the Controller of GP Natural Resource Partners LLC. He has served as Controller of the general partner of Western Pocahontas Properties Limited Partnership and of New Gauley Coal Corporation since 1988 and of the general partner of Great Northern Properties Limited Partnership since 1992. He was also Controller of Blackhawk Mining Co., Quintana Coal Co. and other related operations from 1985 to 1988. Prior to that time, Mr. Hudson worked in public accounting.
 
Robert T. Blakely joined the Board of Directors of GP Natural Resource Partners LLC in January 2003. He currently serves as Executive Vice President and Chief Financial Officer of Fannie Mae. From mid-2003 through January 2006, he was Executive Vice President and Chief Financial Officer of MCI, Inc. From mid-2002 through mid-2003, he served as President of Performance Enhancement Group, which was formed to acquire manufacturers of high performance and racing components designed for automotive and marine-engine applications. He previously served as Executive Vice President and Chief Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco, Inc. from 1981 until 1999 as well as a Managing Director at Morgan Stanley. He 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.
 
David M. Carmichael is a member of the Board of Directors of GP Natural Resource Partners LLC. He currently is a private investor. Mr. Carmichael is the former Vice Chairman of KN Energy and the former Chairman and Chief Executive Officer of American Oil and Gas Corporation, CARCON Corporation and WellTech, Inc. 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 Compensation Committee for ENSCO and on both the Compensation and Nominating and Governance Committees for Cabot. He also currently serves as a trustee of the Texas Heart Institute.


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J. Matthew Fifield is a member of the Board of Directors of GP Natural Resource Partners LLC. 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 October 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 September 2002 until June 2004. Prior to business school he served as Director — Corporate Development for Jupiter Media Metrix from January 2001 to July 2002 and as an associate director of UBS Warburg, where he worked from 1997 to 2000.
 
Robert B. Karn III is a member of the Board of Directors of GP Natural Resource Partners LLC. 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 and the Board of Trustees of Fiduciary Claymore MLP Opportunity Fund and Fiduciary Claymore Dynamic Equity Fund.
 
S. Reed Morian is a member of the Board of Directors of GP Natural Resource Partners LLC. 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 has served on the Board of Directors for the Federal Reserve Bank of Dallas-Houston Branch since April 2003 and as a Director of Prosperity Bancshares, Inc. since March 2005.
 
W. W. Scott, Jr. is a member of the Board of Directors of GP Natural Resource Partners LLC. 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 on March 5, 2004. Mr. Smith is the Senior Vice President and Treasurer of American Electric Power Company, Inc. 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.
 
Corporate Governance
 
Board Attendance and Executive Sessions
 
The Board of Directors met eleven times in 2006. During that period, each director attended 90% or more of the meetings of the Board, and average attendance was 97%. Pursuant to our Corporate Governance Guidelines, the non-management directors meet in executive session at least quarterly. In addition, if the Board of Directors determines that any non-management directors are not independent under criteria established by the New York Stock Exchange, an executive session comprised solely of independent directors will be held at least once a year. During 2006, our non-management directors met in executive session four times. The presiding director of these meetings was rotated among the four independent directors on the Board. In addition, our independent directors met one time in executive session in 2006. Mr. Carmichael was the presiding director at this meeting. Interested parties


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may communicate with our non-management directors by writing a letter to the Chairman of our Audit Committee, NRP Board of Directors, 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
 
Independence of Directors
 
The Board of Directors has determined that Messrs. Blakely, Carmichael, Karn and Smith are independent under the standards set forth in Section 303A.02(a) of the New York Stock Exchange’s listing standards and under Item 7(d)(3)(iv) of Schedule 14A under the Securities Exchange Act of 1934. Although we had a majority of independent directors in 2006, 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. With the addition of Mr. Fifield to the Board as a non-independent director in January 2007, we intend to appoint an additional independent director during 2007. To contact the independent directors, please write to: Chairman of the Audit Committee, NRP Board of Directors, 601 Jefferson Street, Suite 3600, Houston, TX 77002. The Board has three committees staffed solely by independent directors. Mr. Karn, Mr. Smith and Mr. Blakely are “Audit Committee Financial Experts” as determined pursuant to Item 401(h) of Regulation S-K.
 
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 2006, 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 recommended to the Board of Directors the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 2006 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 under Statement on Auditing Standards No. 61, as amended by Statement on Auditing Standards No. 90 (communications 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 3600T of the Public Company Accounting Oversight Board, which has adopted on an interim basis Independence Standards Board Standard No. 1 (independence discussions with audit committees), and considered with the auditors whether the provision of non-audit services provided by them to the partnership during 2006 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 2006, 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


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statements and reports, and of the independent auditors, who, in their report, express an opinion on the conformity of our annual financial statements with 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, 2006, for filing with the Securities and Exchange Commission.
 
Robert B. Karn, Chairman
Robert T. Blakely
Stephen P. Smith
David M. Carmichael
 
Compensation, Nominating and Goverance Committee Authority
 
Executive officer compensation is administered by the Compensation, Nominating and Goverance Committee, or CNG Committee, which is comprised of three members. Mr. Carmichael, the Chairman, and Mr. Karn have served on this committee since 2002, and Mr. Blakely joined the committee in early 2003. 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; and
 
  •  reviewing and recommending the annual and long-term incentive plans in which our executive officers participate.
 
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.
 
Report of the Compensation, Nominating and Governance Committee
 
The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management. Based on the reviews and discussions referred to in the foregoing sentence, the CNG Committee recommended to the board of directors that the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year ended December 31, 2006.
 
David Carmichael, Chairman
Robert Karn III
Robert T. Blakely
 
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, 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


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transactions in our equity securities during 2006, with the exception of Mr. Robertson and Mr. Carter, who each filed 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 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 2006, 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.


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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 Huntington, West Virginia are employed by the general partner of Western Pocahontas Properties Limited Partnership, and our executive officers based in Houston, Texas are employed by Quintana Minerals Corporation, 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 their 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 goal 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 investors. 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.
 
Our philosophy is that optimal alignment between our unitholders and our executive officers is best achieved by providing a greater amount of total compensation in the form of equity-based compensation rather than salary. 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.
 
Importantly, Mr. Robertson does not receive a salary or bonus in his capacity as CEO, but is compensated exclusively through long-term phantom unit grants awarded by the CNG Committee and the incentive distribution rights held by the general partner, of which he indirectly owns 78%. Mr. Robertson also owns in excess of 25% of the outstanding equity of NRP, and thus his interests are directly aligned with our unitholders.
 
Every December, our CNG Committee meets to review the performance of the executive officers and the amount of time expected to be spent by each NRP officer on NRP business in the coming year. The percentages of time allocation range from 50% for our Chief Executive Officer to 100% for our Vice President — Business Development and our Vice President — Investor Relations. Most of our executive officers spend in excess of 85% of their time on NRP matters and NRP bears the allocated cost of their time spent on NRP matters. Based on their review, the CNG Committee makes recommendations to the full board of directors with respect to the salaries and annual cash bonuses for each of the executive officers.
 
In February, the CNG Committee meets to approve the long-term incentive awards for the executive officers. The CNG Committee considers the performance of the partnership, the performance of the individuals and the outlook for the future in determining the amounts of the awards. Because we are a partnership, tax and accounting conventions make it more costly for us to issue additional common units or options as incentive compensation. Consequently, we have no outstanding options or restricted units and have no plans to issue options or restricted units in the future. Instead, we have issued phantom units to our executive officers that are paid in cash based on the


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20-day average closing price of our common units prior to vesting. The phantom units typically vest four years from the date of grant.
 
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
 
In 2005, the CNG Committee engaged a consultant to review the executive officer and director compensation, and in 2006, the CNG Committee requested that the consultant update the information with respect to directors’ fees. The CNG Committee considered the advice of the consultant as only one factor among the other items discussed in this compensation discussion and analysis. For a more detailed description of the CNG Committee and its responsibilities, 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 were actively involved in providing recommendations to the CNG Committee in its evaluation of the 2006 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 2006 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 and reimbursed by NRP to compensate those companies for services rendered to us by the executive officers during the fiscal year. 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. As discussed above, the base salaries are paid by Western Pocahontas Properties and Quintana, and reimbursed by us based on the time allocated by each executive officer to our business. The CNG Committee reviews and approves the full salaries paid to each executive officer by Western Pocahontas and Quintana, 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 participated in two cash incentive programs in 2006. The first program is a discretionary cash bonus award approved in December by the CNG Committee based on the same criteria used to evaluate the annual base salaries. The bonuses paid in 2006 under this program are disclosed in the Summary Compensation Table under the Bonus column. In line with our philosophy of primarily using the long-term compensation to motivate and retain our executive officers, on average these bonuses only represented approximately 55% of the annual salaries paid to the named executive officers, with the actual percentage varying by officer. As with the base salaries, there are no formulas or specific performance targets related to these awards.


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Under the second cash incentive program, our general partner has set aside 7.5% of the cash it receives on an annual basis with respect to its incentive distribution rights under our partnership agreement for awards to our executive officers. The cash awards that our officers receive under this plan are reviewed, evaluated and approved by the CNG Committee. Because they are ultimately reimbursed by the general partner, the payments do not have any impact on our financial statements or cash available for distribution to our unitholders. Because the cost of these awards is not borne by NRP, we have disclosed the amounts of these awards under the All Other Compensation column in the Summary Compensation Table. We believe that these awards align the interests of our executive officers directly with our unitholders in consistently increasing our quarterly distributions.
 
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 the 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 the company, particularly the growth of the quarterly distribution and its impact on our unit price, over an extended time horizon.
 
When we completed our initial public offering just over four years ago, we granted each executive officer long-term incentive compensation that vested over a four year period. A portion of the award has vested each year, but a substantial bulk of the compensation will be paid in 2007, the fourth year of the initial grant. Subsequent to the initial grant, our CNG Committee has approved annual awards of phantom units that vest four years from the date of grant. The amounts disclosed in the Phantom Unit Awards column in the Summary Compensation Table represent the expense incurred by NRP in 2006 with respect to awards granted in 2003-2006, although the forfeiture component that is deducted in the FAS 123R calculation has been added back in for purposes of the table. The size and value of the awards that the CNG Committee approved in 2006 reflect both the success of NRP in increasing our distribution by 15% in 2005 and the desire of the CNG Committee to motivate the executive officers to continue the growth over the long term.
 
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 premium, with the company paying the remainder. These benefits are offered on the same basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee allocates time to our business.
 
Quintana and Western Pocahontas also maintain 401(k) and defined contribution retirement plans. Quintana and Western Pocahontas both match the employee contributions under the 401(k) plan 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 compensation 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. 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 2006 we also reimbursed Quintana and Western Pocahontas for car allowances provided to Messrs. Carter, Dunlap and Wall. No named executive officer received a perquisite valued in excess of $10,000 during 2006.
 
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, 2006, our named executive officers held 119,666 phantom units that have been granted as compensation. In addition, Mr. Robertson directly or indirectly owns 6,020,377 common units and 2,720,335 subordinated units.


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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 2006. 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.
 
We adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payment,” effective January 1, 2006 using the modified prospective approach. FAS 123R 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 the estimated fair value to expense over the service or vesting period of the grant. In addition, FAS 123R requires that the fair value be recalculated at each reporting date over the service or vesting period of the grant. We continue to believe that phantom units are an essential component of our compensation strategy, and we intend to continue to offer these awards in the future.


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Summary Compensation Table
 
The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation expense in 2006 based on time allocated by each individual to Natural Resource Partners. In 2006, Mr. Robertson, Mr. Dunlap, Mr. Carter, Mr. Hogan and Mr. Wall spent approximately 50%, 84%, 97%, 85% and 95% of their time on NRP matters.
 
                                                                         
                                        Change in
             
                                        Pension Value
             
                                  Non-Equity
    and Non-Qualified
             
                      Phantom
          Incentive
    Deferred
             
                      Unit
    Option
    Plan
    Compensation
    All Other
       
Name and Principal
        Salary
    Bonus
    Awards(1)
    Awards
    Compensation
    Earnings
    Compensation(2)
    Total
 
Position
  Year     ($)     ($)     ($)     ($)     ($)     ($)     ($)     ($)  
 
Corbin J. Robertson, Jr.
Chairman and CEO
    2006                   899,387                         74,857       974,244  
Dwight L. Dunlap
CFO and Treasurer
    2006       176,908       100,000       298,926                         86,164       661,998  
Nick Carter
President and COO
    2006       261,900       200,000       449,683                         110,973       1,022,556  
Wyatt L. Hogan
Vice President, General
Counsel and Secretary
    2006       174,018       60,000       183,384                         79,632       497,034  
Kevin F. Wall
Vice President and Chief Engineer
    2006       128,250       75,000       219,756                         65,664       488,670  
 
 
(1) Amounts represent the expense incurred by NRP for awards granted from 2003-2006 calculated in accordance with FAS 123R, with the exception that the forfeiture deductions in the FAS 123R calculation have been added back in for purposes of the table. For a description of the assumptions made in the FAS 123R calculation, please see Note 11 in Notes to Consolidated Financial Statements on page 61 of this Form 10-K.
 
(2) Includes portions of automobile allowance, 401(k) matching and retirement contributions allocated to Natural Resource Partners by Quintana Minerals Corporation and Western Pocahontas Properties Limited Partnership. Also includes cash compensation paid by the general partner to each named executive officer. The general partner may distribute up to 7.5% of any cash it receives with respect to its incentive distribution rights. We do not reimburse the general partner for any of the payments with respect to the incentive distribution rights.
 
Grants of Plan-Based Awards in 2006
 
                         
          All Other
       
          Unit Awards:
    Grant Date Fair
 
          Number of
    Value of
 
          Phantom Units(1)
    Unit Awards(2)
 
Named Executive Officer
  Grant Date     (#)     ($)  
 
Corbin J. Robertson, Jr. 
    2/13/2006       10,000       621,200  
Dwight L. Dunlap
    2/13/2006       3,500       217,420  
Nick Carter
    2/13/2006       5,000       310,600  
Wyatt L. Hogan
    2/13/2006       2,900       180,148  
Kevin F. Wall
    2/13/2006       2,600       161,512  
 
 
(1) The phantom units were granted in February 2006 and will vest in February 2010.
 
(2) Amounts represent the expense incurred by NRP for awards granted in 2006 calculated in accordance with FAS 123R, with the exception that the forfeiture deductions in the FAS 123R calculation have been added back in for purposes of the table. For a description of the assumptions made in the FAS 123R calculation, please see Note 11 in Notes to Consolidated Financial Statements on page 61 of this Form 10-K.
 
None of our executive officers has an employment agreement, and the salary, bonus and phantom unit awards noted above are approved by the CNG Committee. Please see our disclosure in the Compensation Discussion and Analysis section of this Form 10-K for a description of the factors that the CNG Committee considers in determining the amount of each component of the compensation.


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Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the CNG Committee have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce any award to a participant without the consent of the participant.
 
The CNG Committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of NRP, our general partner or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.
 
As stated above in the Compensation Discussion and Analysis, we have no outstanding option grants, and do not intend to grant in the future any options or restricted unit awards. The CNG Committee regularly makes awards of phantom units on an annual basis in February. Each award of phantom units vests four years from the date of grant, so that the awards listed above will vest in February 2010.
 
Outstanding Awards at December 31, 2006
 
The table below shows the total number of outstanding phantom units held by each named executive officer at December 31, 2006. The phantom units shown below have been awarded over the last four years, and the final component will vest in 2010.
 
                 
    Number of
    Market Value
 
    Phantom Units That
    of Phantom Units That
 
    Have Not Vested
    Have Not Vested(1)
 
Named Executive Officer
  (#)     ($)  
 
Corbin J. Robertson, Jr.(2)
    52,365       3,034,552  
Dwight L. Dunlap(3)
    17,457       1,011,633  
Nick Carter(4)
    26,182       1,517,247  
Wyatt L. Hogan(5)
    10,826       627,367  
Kevin F. Wall(6)
    12,836       743,846  
 
 
(1) Based on a unit price of $57.95, the closing price for the common units on December 29, 2006.
 
(2) Includes 23,525 units vesting in 2007, 8,840 units vesting in 2008, 10,000 units vesting in 2009 and 10,000 units vesting in 2010.
 
(3) Includes 7,337 units vesting in 2007, 3,120 units vesting in 2008, 3,500 units vesting 2009 and 3,500 units vesting in 2010.
 
(4) Includes 11,762 units vesting in 2007, 4,420 units vesting in 2008, 5,000 units vesting in 2009 and 5,000 units vesting in 2010.
 
(5) Includes 2,426 units vesting in 2007, 2,600 units vesting in 2008, 2,900 units vesting in 2009 and 2,900 units vesting in 2010.
 
(6) Includes 5,396 units vesting in 2007, 2,340 units vesting in 2008, 2,500 units vesting in 2009 and 2,600 units vesting in 2010.


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Phantom Units Vested in 2006
 
The table below shows the phantom units that vested with respect to each named executive officer in 2006, along with the value realized by each individual.
 
                 
    Number of
       
    Phantom Units That
    Value Realized on
 
    Vested
    Vesting
 
Named Executive Officer
  (#)     ($)  
 
Corbin J. Robertson, Jr.(1)
    3,667       193,691  
Dwight L. Dunlap(1)
    1,143       60,373  
Nick Carter(1)
    1,833       96,819  
Wyatt L. Hogan(2)
    214       11,997  
Kevin F. Wall(1)
    841       44,422  
 
 
(1) Based on a 20-day average closing price for the common units of $52.82.
 
(2) Based on a 20-day average closing price for the common units of $56.06.
 
Potential Payments upon Termination or Change in Control
 
None of our executive executive officers have entered into employment agreements with Natural Resource Partners or its affiliates. Consequently, there are no severance benefits payable to any executive officer upon the termination of their employment. The annual base salaries, bonuses and other compensation are all determined by the CNG Committee in consultation with Mr. Robertson, Mr. Carter and the full board of directors. Upon the occurrence of a change in control of NRP,our general partner or GP Natural Resource Partners LLC, the outstanding phantom unit awards held by each of our executive officers would immediately vest. The table below indicates the impact of a change in control on the outstanding equity-based awards at December 31, 2006, based on the closing price of the common units of $57.95 on December 29, 2006.
 
                         
    Number of
    Potential
    Potential
 
    Phantom
    Post-Employment
    Cash Payments
 
    Units
    Payments
    Required Upon
 
    That Have
    Required Upon
    Change in
 
    Not Vested
    Change in Control
    Control
 
Named Executive Officer
  (#)     ($)     ($)  
 
Corbin J. Robertson, Jr. 
    52,365             2,935,582  
Dwight L. Dunlap
    17,457             978,639  
Nick Carter
    26,182             1,467,763  
Wyatt L. Hogan
    10,826             606,906  
Kevin F. Wall
    12,836             719,586  


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Director’s Compensation for the Year Ended December 31, 2006
 
The table below shows the directors’ compensation for the year ended December 31, 2006. As with our named executive officers, we do not grant any options or restricted units to our directors.
 
                                                         
                            Change in
             
                            Pension Value
             
                            and
             
                            Nonqualified
             
    Fees Earned
                Non-Equity
    Deferred
             
    or Paid in
    Phantom
    Option
    Incentive Plan
    Compensation
    All Other
       
    Cash
    Unit Awards(1)(2)
    Awards
    Compensation
    Earnings
    Compensation
    Total
 
Name
  ($)     ($)     ($)     ($)     ($)     ($)     ($)  
 
Robert Blakely
    42,000       92,464                               134,464  
David Carmichael
    44,000       90,569                               134,569  
J. Matthew Fifield(3)
                                         
Robert Karn III
    49,000       90,569                               139,569  
S. Reed Morian
    31,000       90,569                               121,569  
Stephen Smith
    36,000       90,569                               126,569  
W. W. Scott, Jr. 
    31,000       90,569                               121,569  
 
 
(1) Amounts represent the expense incurred by NRP for awards granted from 2003-2006 calculated in accordance with FAS 123R, with the exception that the forfeiture deductions in the FAS 123R calculation have been added back in for purposes of the table. For a description of the assumptions made in the FAS 123R calculation, please see Note 11 in Notes to Consolidated Financial Statements on page 61 of this Form 10-K.
 
(2) As of December 31, 2006, each director other than Mr. Fifield held 5,400 phantom units that vest in annual increments of 1,350 units in each of 2007, 2008, 2009 and 2010.
 
(3) Mr. Fifield joined the Board on January 4, 2007 and thus received no compensation with respect to 2006.
 
In 2006, our non-employee directors received an annual retainer of $20,000, payable quarterly, plus $1,000 for attending board and committee meetings. In addition, Mr. Karn received $6,000 for his services as chairman of the Audit Committee and Mr. Carmichael and Mr. Blakely each received $2,000 for their services as chairmen of the CNG and Conflicts Committees, respectively. In addition, each non-employee director received a grant of 1,350 phantom units that will vest in February 2010. Mr. Blakely held a phantom unit award that vested in February 2006 with respect to which NRP paid out $72,884, but no other director had an award vest in 2006.
 
Beginning in 2007, we changed the structure of our director compensation. We have eliminated meeting fees for the directors and increased the annual retainer to $35,000. Each chairman of a committee will receive an annual fee of $10,000 for serving as chairman, and each committee member will receive $5,000 for serving on a committee. In addition, on February 13, 2007, each director received a phantom unit grant of 1,500 units that will vest in 2011. Mr. Fifield received a grant of 6,000 phantom units on February 13, 2007, of which 1,500 units vest annually in each of 2008, 2009, 2010 and 2011. Also on February 13, 2007, the CNG Committee awarded each director, other than Mr. Fifield, an additional 450 units, of which 150 units will vest in each of 2008, 2009 and 2010.


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Item 12.   Security Ownership of Certain Beneficial Owners and Management
 
The following table sets forth, as of February 27, 2007 the amount and percentage of our common, subordinated and Class B units beneficially held by (1) each person known to us to beneficially own 5% or more of any class of our units, (2) by each of the directors and executive officers and (3) by all directors and executive officers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the units shown.
 
                                                         
          Percentage
          Percentage of
          Percentage
    Percentage
 
    Common
    of Common
    Subordinated
    Subordinated
    Class B
    of Class B
    of Total
 
Name of Beneficial Owner
  Units     Units(1)     Units     Units(2)     Units     Units(3)     Units  
 
Corbin J. Robertson, Jr.(4)
    6,089,907       23.4 %     2,720,335       47.9 %                 27.4 %
Western Pocahontas Properties(5)(6)
    5,774,048       22.2 %     2,615,882       46.1 %                     26.1 %
Adena Minerals LLC(7)
    3,913,080       15.1 %                 541,956       100.0 %     13.8 %
Dingess-Rum Properties, Inc.(8)
    2,400,000       9.2 %                                 7.5 %
Great Northern Properties(6)
    931,747       3.6 %     558,032       9.8 %                 4.6 %
Neuberger Berman Inc.(9)
    444,389       1.7 %     698,211       12.3 %                 3.5 %
Nick Carter.(10)
    5,401       *     4       *                 *  
Dwight L. Dunlap
    4,000       *                             *  
Kevin F. Wall
    500       *                             *  
Kathy E. Hager
    4,377       *                             *  
Wyatt L. Hogan(11)
    500       *                             *  
Kenneth Hudson
    500       *                             *  
Kevin J. Craig
                                         
Robert T. Blakely
                                         
David M. Carmichael
    5,000       *                             *  
J. Matthew Fifield
                                         
Robert B. Karn III
    2,500       *                             *  
S. Reed Morian
    10,000       *                             *  
W. W. Scott, Jr. 
    5,310       *                             *  
Stephen P. Smith
                                         
Directors and Officers as a Group
    6,127,992       23.6 %     2,720,335       47.9 %                 27.5 %
 
Less than one percent.
(1) Based upon 25,976,795 common units issued and outstanding. Unless otherwise noted, beneficial ownership is less than 1%.
(2) Based upon 5,676,817 subordinated units issued and outstanding. Unless otherwise noted, beneficial ownership is less than 1%.
(3) Based upon 541,956 Class B units issued and outstanding. Unless otherwise noted, beneficial ownership is less than 1%.
(4) Mr. Robertson may be deemed to beneficially own the 5,774,048 common units and 2,615,882 subordinated units owned by Western Pocahontas Properties Limited Partnership, and 230,559 common units and 104,453 subordinated units owned by New Gauley Coal Corporation. Also included are 69,530 common units held by William K. Robertson 1992 Management Trust of which Mr. Robertson is the trustee, and has voting control, but not direct ownership. Also included are 15,770 common units held by Barbara Robertson, Mr. Robertson’s spouse. Mr. Robertson’s address is 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
(5) These units may be deemed to be beneficially owned by Mr. Robertson.
(6) The address of Western Pocahontas Properties Limited Partnership and Great Northern Properties Limited Partnership is 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
(7) The address of Adena Minerals LLC is 3801 PGA Boulevard, Suite 903, Palm Beach Gardens, FL 33410.
(8) The address of Dingess-Rum Properties, Inc. is 405 Capital Street, Suite 701, Charleston, WV 25301.
(9) Includes 242,857 common units and 485,714 subordinated units over which Neuberger Berman has sole voting and shared dispositive power and 57,386 common units and 114,772 subordinated units that are for individual client accounts and over which Neuberger Berman has shared dispositive power but no voting power. The address of Neuberger Berman Inc. is 605 Third Avenue, New York, NY 10158.
(10) Includes 101 common units and 4 subordinated units held by Mr. Carter’s spouse.
(11) Of these common units, 250 common units are owned by the Anna Margaret Hogan 2002 Trust and 250 common units are owned by the Alice Elizabeth Hogan 2002 Trust. Mr. Hogan is a trustee of each of these trusts.


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Item 13.   Certain Relationships and Related Transactions, and Director Independence
 
Distributions and Payments to the General Partner and its Affiliates
 
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and any liquidation of Natural Resource Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
 
Distributions of available cash to our general partner and its affiliates We will generally make cash distributions 98% to the unitholders, including affiliates of our general partner, as holders of all of the subordinated units, and 2% to the general partner. In addition, if distributions exceed the target distribution levels, the holders of the incentive distribution rights, including our general partner, will be entitled to increasing percentages of the distributions, up to an aggregate of 48% of the distributions above the highest target level.
 
Other payments to our general partner and its affiliates Assuming we have sufficient available cash to pay the current quarterly distribution of $0.88 on all of our outstanding units for four quarters in 2007, our general partner would receive distributions of approximately $2.7 million on its 2% general partner interest and our affiliates would receive distributions of approximately $38.2 million on their common units, $11.5 million on their subordinated units and $1.9 million on their Class B units. In addition in 2007, our general partner and affiliates of our general partner would receive an aggregate of approximately $20.4 million with respect to their incentive distribution rights. Our general partner and its affiliates will not receive any management fee or other compensation for the management of our partnership. Our general partner and its affiliates will be reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner has the sole discretion in determining the amount of these expenses.
 
Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
 
Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
 
Omnibus Agreement
 
Non-competition Provisions
 
As part of the omnibus agreement entered into concurrently with the closing of our initial public offering, the WPP Group and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the GP affiliates, each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a “restricted business”) in the specific circumstances described below:
 
  •  the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal reserves within the United States; and


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  •  the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.
 
“Affiliate” means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group and their respective controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us.
 
A GP affiliate may, directly or indirectly, engage in a restricted business if:
 
  •  the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.
 
  •  the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.
 
  •  the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under the procedures described below.
 
  •  its ownership in the restricted business consists solely of a noncontrolling equity interest.
 
For purposes of this paragraph, “fair market value” means the fair market value as determined in good faith by the relevant GP affiliate.
 
The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in by the WPP Group at closing of our initial public offering, may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be acquired.
 
If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer us the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph, “restricted business” excludes a general partner interest or managing member interest, which is addressed in a separate restriction summarized below. For purposes of this paragraph only, “fair market value” means the fair market value as determined in good faith by the relevant GP affiliate.
 
If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate may operate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.
 
If, at the end of the two year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP


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affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will be under no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned.
 
In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offer procedures described above will recommence.
 
If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly held limited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPP Group may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures described above.
 
The omnibus agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of the WPP Group under the omnibus agreement terminate when the WPP Group and its affiliates cease to participate in the control of the general partner.
 
The Cline Group
 
On January 4, 2007, we acquired from Adena Minerals, LLC four entities that own approximately 49 million tons of coal reserves in West Virginia and Illinois that are leased to active mining operations, as well as associated transportation and infrastructure assets at those mines. The reserves consist of 37 million tons at Adena’s Gatling mining operation in Mason County, West Virginia and 12 million tons adjacent to reserves currently owned by the Partnership at Adena affiliate Williamson Energy’s Pond Creek No. 1 mine in Southern Illinois. In consideration therefor, Adena received 3,913,080 common units and 541,956 Class B units representing limited partner interests in NRP and a 22% interest in our general partner and in our outstanding incentive distribution rights. Adena is an affiliate of The Cline Group, a private coal company that controls over 3 billion tons of coal reserves in the Illinois and Northern Appalachian coal basins.
 
Second Contribution Agreement.  At the closing of the acquisition, we executed a Second Contribution Agreement, pursuant to which we agreed to acquire from Adena two entities that own coal reserves in Meigs County, Ohio and associated transportation infrastructure. As consideration, Adena will receive 2,280,000 Class B Units (unless we have received unitholder approval to convert the Class B Units to common units, in which case Adena will receive 2,280,000 common units), as well as an additional 9% interest in the general partner and our outstanding incentive distribution rights. The transactions contemplated by the Second Contribution Agreement are expected to close, subject to customary closing conditions, upon commencement of production of the Ohio coal reserves, which is currently expected to occur in 2008.
 
Restricted Business Contribution Agreement.  Also at the closing, Christopher Cline, Foresight Reserves LP and Adena (collectively, the “Cline Entities”) and NRP executed a Restricted Business Contribution Agreement. Pursuant to the terms of the Restricted Business Contribution Agreement, the Cline Entities and their affiliates will be obligated to offer to NRP any business owned, operated or invested in by the Cline Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in transportation infrastructure relating to future mine developments by the Cline Entities in Illinois. In addition, certain we created an area of mutual interest (the “AMI”) encompassing the properties to be acquired by us pursuant to the Contribution Agreement and the Second Contribution Agreement. During the applicable term of the Restricted Business Contribution Agreement, the Cline Entities will be obligated to contribute any coal reserves held or acquired by the Cline Entities or their affiliates within the AMI to us. In connection with the offer of mineral


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properties by the Cline Entities to NRP, including pursuant to the Second Contribution Agreement, the parties to the Restricted Business Contribution Agreement will negotiate and agree upon an area of mutual interest around such minerals, which will supplement and become a part of the AMI.
 
Investor Rights Agreement.  Also at the closing, NRP and certain affiliates and Adena executed an Investor Rights Agreement pursuant to which Adena was granted certain management rights. Specifically, Adena has the right to name two directors (one of which will be independent) to the board of directors of our managing general partner so long as Adena beneficially owns either 5% of our limited partnership interest or 5% of our general partner’s limited partnership interest and so long as certain rights under our managing general partner’s LLC Agreement have not been exercised by Adena or Mr. Robertson. Adena nominated J. Matthew Fifield, Managing Director of Adena, to serve as one of the two directors and anticipates nominating an independent director in the near future. The independent director will be appointed to at least one committee for which such director meets the applicable qualifications. Adena will also have the right, pursuant to the terms of the Investor Rights Agreement, to withhold its consent to the sale or other disposition of any entity or assets contributed by the Cline entities to NRP, and any such sale or disposition will be void without Adena’s consent.
 
Quintana Energy Partners, L.P.
 
In 2006, Corbin J. Robertson, Jr. formed Quintana Energy Partners L.P., a $650 million private equity fund focused on investments in the energy business. In connection with the formation of QEP, NRP’s Board of Directors adopted a formal conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by QEP. QEP’s governance documents reflect the guidelines set forth in NRP’s conflicts policy. The basic tenets of the policy are set forth in the bullets below.
 
  •  NRP’s business strategy is focused on the ownership of non-operated royalty producing coal properties in North America and the leasing of these coal reserves. In addition, NRP has extended its business into the ownership and leasing of other non-operated royalty producing extracted hard mineral properties. NRP also has added the transportation, storage and related logistics activities related to coal and other hard minerals to its business strategy. These current and prospective businesses are referred to as the “NRP Businesses.”
 
  •  NRP’s business strategy does not, and is not expected to, include oil and gas exploration or development (except for non-operated royalty interests in coal bed methane production ancillary to its coal business), investments which do not generate “qualifying income” for a publicly traded partnership under U.S. tax regulations, investments outside of North America and other “midstream” or refining businesses which do not involve coal or other hard extracted minerals, including the gathering, processing, fractionation, refining, storage or transportation of oil, natural gas or natural gas liquids. NRP’s business strategy also does not, and is not expected to include, coal mining or mining for other hard minerals. The businesses and investments described in this paragraph are referred to as the “Non-NRP Businesses”.
 
  •  For so long as Corbin Robertson, Jr. remains both an affiliate of the general partner of Quintana Energy Partners and an executive officer or director of NRP or an affiliate of its general partner, before making an investment in an NRP Business, Quintana Energy Partners will first offer such opportunity in its entirety to NRP. NRP may elect to pursue such investment wholly for its own account, to pursue the opportunity jointly with Quintana Energy Partners or not to pursue such opportunity. If NRP elects not to pursue an NRP Business investment opportunity, Quintana Energy Partners may pursue the investment for its own account. Decisions in respect of such opportunities will be made by NRP by the Conflicts Committee of the Board of Directors of the general partner; provided, however, that decisions in respect of potential investments of $20 million or less may be made by an executive officer of the general partner to whom such authority is delegated by the Conflicts Committee. NRP will undertake to advise Quintana Energy Partners of its decision regarding a potential investment opportunity within 10 business days of the identification of such opportunity to either the Conflicts Committee or such designated officer, as applicable.
 
  •  Neither Quintana Energy Partners nor Mr. Robertson will have any obligation to offer investments relating to Non-NRP Businesses to NRP and that NRP will not have any obligation to refrain from pursuing a Non-NRP Business if there is a change in its business strategy. If such a change in strategy occurs, it is expected that the Conflicts Committee would work together with Quintana Energy Partners to adopt mutually agreed


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  practices and procedures in order to safeguard confidential information relating to potential investments and to address any potential or actual conflicts of interest involving Quintana Energy Partners investments or the activities of Mr. Robertson.
 
In February 2007, QEP acquired a 43% membership interest in Taggart Global, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. NRP currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. NRP will own and lease the plants to Taggart Global, who 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. In 2006, NRP and Taggart Global jointly financed and developed two such plants in West Virginia.
 
Conflicts of Interest
 
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group, the Cline Group, and their affiliates) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLC have fiduciary duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
 
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the board of directors of our general partner of such resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. In effect, these provisions limit our general partner’s fiduciary duties to our unitholders. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties. The partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that might, without those limitations, constitute breaches of fiduciary duty.
 
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:
 
  •  approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or course of action that has not received approval;
 
  •  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  •  fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement, consider:
 
  •  the relative interests of any party to such conflict and the benefits and burdens relating to such interest;
 
  •  any customary or accepted industry practices or historical dealings with a particular person or entity;
 
  •  generally accepted accounting practices or principles; and
 
  •  such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
 
Conflicts of interest could arise in the situations described below, among others.


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Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.
 
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
 
  •  amount and timing of asset purchases and sales;
 
  •  cash expenditures;
 
  •  borrowings;
 
  •  the issuance of additional units; and
 
  •  the creation, reduction or increase of reserves in any quarter.
 
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of:
 
  •  enabling our general partner to receive distributions on any subordinated units held by our general partner or the incentive distribution rights; or
 
  •  hastening the expiration of the subordination period.
 
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units, Class B units and subordinated units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding units.
 
The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries.
 
We do not have any officers or employees and rely solely on officers and employees of GP Natural Resource Partners LLC and its affiliates.
 
We do not have any officers or employees and rely solely on officers and employees of GP Natural Resource Partners LLC and its affiliates. Affiliates of GP Natural Resource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource Partners LLC are not required to work full time on our affairs. These officers devote significant time to the affairs of the WPP Group or its affiliates and are compensated by these affiliates for the services rendered to them.
 
We reimburse our general partner and its affiliates for expenses.
 
We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
 
Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.


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Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.
 
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
 
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-length negotiations.
 
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length negotiations.
 
All of these transactions entered into after our initial public offering are on terms that are fair and reasonable to us.
 
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
 
We may not choose to retain separate counsel for ourselves or for the holders of common units.
 
The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
 
Our general partner’s affiliates may compete with us.
 
The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement, the omnibus agreement and the Restricted Business Contribution Agreement, affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us.
 
Director Independence
 
For a discussion of the independence of the members of the board of directors of our managing general partner under applicable standards, please read “Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance — Corporate Governance — Independence of Directors,” which is incorporated by reference into this Item 13.


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Item 14.   Principal Accountant Fees and Services
 
The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended and we engaged Ernst & Young LLP to audit our accounts and assist with tax work for fiscal 2006 and 2005. Fees (including out-of-pocket costs) incurred from Ernst & Young LLP for services for fiscal years 2006 and 2005 totaled $0.8 million and $0.6 million, respectively. All of our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board of Directors. The following table presents fees for professional services rendered by Ernst &Young LLP:
 
                 
    2006     2005  
 
Audit Fees(1)
  $ 385,725     $ 403,633  
Audit-Related Fees
           
Tax Fees(2)
  $ 400,920     $ 274,840  
All Other Fees
           
 
 
(1) Audit fees include fees associated with the annual audit of our consolidated financial statements and reviews of our quarterly financial statement for inclusion in our Form 10-Q. Audit fees for 2005 also include $88,200 in fees related to FRC-WPP NRP Investment L.P.’s sale of subordinated units in a public offering in August 2005. FRC-WPP NRP Investment L.P. paid the fee to Ernst and Young out of the proceeds of the sale. We did not incur any of the fees or expenses associated with the sale.
 
(2) Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1.
 
Audit and Non-Audit Services Pre-Approval Policy
 
I.   Statement of Principles
 
Under the Sarbanes-Oxley Act of 2002 (the “Act”), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the Securities and Exchange Commission (the “SEC”) has issued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the “Policy”), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor may be pre-approved.
 
The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee (“general pre-approval”) or require the specific pre-approval of the Audit Committee (“specific pre-approval”). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficient procedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-approval by the Audit Committee.
 
For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The Audit Committee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiarity with our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage or control risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative.


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The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
 
The appendices to this Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any general pre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will add or subtract to the list of general pre-approved services from time to time, based on subsequent determinations.
 
The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by the independent auditor to management.
 
Ernst & Young LLP, our independent auditor has reviewed this Policy and believes that implementation of the policy will not adversely affect its independence.
 
II.   Delegation
 
As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Robert B. Karn III, the Chairman of the Audit Committee. Mr. Karn must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.
 
III.   Audit Services
 
The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annual financial statement audit (including required quarterly reviews), subsidiary audits, equity investment audits and other procedures required to be performed by the independent auditor to be able to form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testing performed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services also include the attestation engagement for the independent auditor’s report on management’s report on internal controls for financial reporting. The Audit Committee monitors the audit services engagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in audit scope, partnership structure or other items.
 
In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other audit services, which are those services that only the independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits for our subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection with securities offerings.
 
IV.   Audit-related Services
 
Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financial statements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does not impair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accounting consultations related to accounting, financial reporting or disclosure matters not classified as “Audit services” assistance with understanding and implementing new accounting and financial reporting guidance from rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal control reporting requirements.


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V.   Tax Services
 
The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advice without impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes it may grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would not impair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of the independent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officer or outside counsel to determine that the tax planning and reporting positions are consistent with this Policy.
 
VI.   Pre-Approval Fee Levels or Budgeted Amounts
 
Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Any proposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overall relationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determine the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
 
VII.   Procedures
 
All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submitted to the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of any such services rendered by the independent auditor.
 
Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the Audit Committee by both the independent auditor and the Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with the SEC’s rules on auditor independence.


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PART IV
 
Item 15.   Exhibits and Financial Statement Schedules
 
(a)(1) and (2) Financial Statements and Schedules
 
Please See Item 8, “Financial Statements and Supplementary Data”
 
(a)(3) Exhibits
 
             
Exhibit
       
Number
     
Description
 
  2 .1    —   Contribution Agreement dated December 14, 2006 by and among Foresight Reserves LP, Adena Minerals, LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 15, 2006)
  2 .2    —   Contribution Agreement dated December 19, 2006 by and among Dingess-Rum Properties, Inc., Natural Resource Partners L.P. and WPP LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 20, 2006)
  2 .3    —   Second Contribution Agreement, dated January 4, 2007, by and among Foresight Reserves LP, Adena Minerals, LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 4, 2007)
  3 .1    —   Third Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of January 4, 2007 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on January 4, 2007)
  3 .2    —   Fourth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of January 4, 2007 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on January 4, 2007)
  4 .1    —   Second Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of January 4, 2007 (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed on January 4, 2007)
  4 .2    —   Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  4 .3    —   Form of Indenture of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532)
  4 .4    —   Form of Indenture of NRP (Operating) LLC (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532)
  4 .5     Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed June 23, 2003)
  4 .6    —   First Supplement to Note Purchase Agreements, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 20, 2005)
  4 .7    —   First Amendment, dated as of July 19, 2005, to Note Purchase Agreements dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on July 20, 2005)
  4 .8     Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K filed June 23, 2003)
  4 .9     Form of Series A Note (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed June 23, 2003)
  4 .10     Form of Series B Note (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed June 23, 2003)
  4 .11     Form of Series C Note (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K filed June 23, 2003)
  4 .12*    —   Form of Series D Note


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Exhibit
       
Number
     
Description
 
  10 .1    —   Credit Agreement, dated as of October 29, 2004, by and among NRP (Operating) LLC, as Borrower, Citibank, N.A., as Administrative Agent, the Banks and WBRD LLC and ACIN LLC, as Guarantors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465)
  10 .2    —   First Amendment to Credit Agreement, dated November 9, 2005 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K, filed on November 10, 2005, File No. 00-1-31465)
  10 .3    —   Contribution, Conveyance and Assumption Agreement by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Ark Land Company, WPP LLC, GNP LLC, NNG LLC, ACIN LLC, Robertson Coal Management LLC, NRP (Operating) LLC, GP Natural Resource Partners LLC, NRP (GP) LP and Natural Resource Partners L.P., dated as of October 17, 2002 (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10 .4    —   Natural Resource Partners Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465)
  10 .5    —   First Amendment to the Natural Resource Partners Long-Term Incentive Plan dated December 8, 2003 (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465)
  10 .6    —   Second Amendment to the Natural Resource Partners Long-Term Incentive Plan (incorporated by reference to the Current Report on Form 8-K, filed on December 13, 2004)
  10 .7    —   Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465)
  10 .8    —   Natural Resource Partners Annual Incentive Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10 .9    —   Omnibus Agreement dated October 17, 2002, by and among Arch Coal, Inc., Ark Land Company, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10 .10    —   Restricted Business Contribution Agreement, dated January 4, 2007, by and among Christopher Cline, Foresight Reserves LP, Adena Minerals, LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 4, 2007)
  10 .11    —   Investor Rights Agreement, dated January 4, 2007, by and among NRP (GP) LP, GP Natural Resource Partners LLC, Robertson Coal Management and Adena Minerals, LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 4, 2007)
  10 .12    —   Form of Coal Mining Lease between Alpha Natural Resources, LLC and WPP LLC (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465)
  10 .13    —   Purchase and Sale Agreement by and between Steelhead Development Company, LLC and ACIN LLC, dated as of May 31, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 1, 2005)
  10 .14    —   Assignment, Waiver and Amendment Agreement, dated January 20, 2006, by and among Williamson Development Company, LLC, ACIN LLC and WPP LLC
  10 .15    —   Memorandum of Understanding by and between NRP (Operating) LLC and Sedgman USA, LLC, dated as of August 23, 2006 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 24, 2006)
  10 .16    —   Purchase and Sale Agreement, dated as of November 24, 2006, by and between NRP (Operating) LLC and The Andrew W. Mellon Foundation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 27, 2006)

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Exhibit
       
Number
     
Description
 
  21 .1*    —   List of subsidiaries of Natural Resource Partners L.P.
  23 .1*    —   Consent of Ernst & Young LLP
  31 .1*    —   Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley
  31 .2*    —   Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley
  32 .1**    —   Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350
  32 .2**    —   Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350
  99 .1*    —   Audited balance sheet of NRP (GP) LP
 
 
Filed herewith
 
** Furnished herewith

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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.
 
NATURAL RESOURCE PARTNERS L.P.
By: NRP (GP) LP, its general partner
  By:  GP NATURAL RESOURCE
PARTNERS LLC, its general partner
 
Date: February 28, 2007
  By: 
/s/  Corbin J. Robertson, Jr.,
Corbin J. Robertson, Jr.,
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
 
Date:  February 28, 2007
  By: 
/s/  Dwight L. Dunlap
Dwight L. Dunlap,
Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
Date:  February 28, 2007
  By: 
/s/  Kenneth Hudson
Kenneth Hudson
Controller
(Principal Accounting Officer)
 
Date:  February 28, 2007
  By: 
/s/  Robert T. Blakely
Robert T. Blakely
Director
 
Date: February 28, 2007
  By: 
/s/  David M. Carmichael
David M. Carmichael
Director
 
Date:  February 28, 2007
  By: 
/s/  J. Matthew Fifield
J. Matthew Fifield
Director
 
Date:  February 28, 2007
  By: 
/s/  Robert B. Karn III
Robert B. Karn III
Director
 
Date:  February 28, 2007
  By: 
/s/  S. Reed Morian
S. Reed Morian
Director
 
Date:  February 28, 2007
  By: 
/s/  W.W. Scott, Jr.
W.W. Scott, Jr.
Director
 
Date:  February 28, 2007
  By: 
/s/  Stephen P. Smith
Stephen P. Smith
Director


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Index to Exhibits
 
             
Exhibit
       
Number
     
Description
 
  2 .1    —   Contribution Agreement dated December 14, 2006 by and among Foresight Reserves LP, Adena Minerals, LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 15, 2006)
  2 .2    —   Contribution Agreement dated December 19, 2006 by and among Dingess-Rum Properties, Inc., Natural Resource Partners L.P. and WPP LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 20, 2006)
  2 .3    —   Second Contribution Agreement, dated January 4, 2007, by and among Foresight Reserves LP, Adena Minerals, LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 4, 2007)
  3 .1    —   Third Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of January 4, 2007 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on January 4, 2007)
  3 .2    —   Fourth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of January 4, 2007 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on January 4, 2007)
  4 .1    —   Second Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of January 4, 2007 (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed on January 4, 2007)
  4 .2    —   Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  4 .3    —   Form of Indenture of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532)
  4 .4    —   Form of Indenture of NRP (Operating) LLC (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532)
  4 .5     Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed June 23, 2003)
  4 .6    —   First Supplement to Note Purchase Agreements, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 20, 2005)
  4 .7    —   First Amendment, dated as of July 19, 2005, to Note Purchase Agreements dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on July 20, 2005)
  4 .8     Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K filed June 23, 2003)
  4 .9     Form of Series A Note (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed June 23, 2003)
  4 .10     Form of Series B Note (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed June 23, 2003)
  4 .11     Form of Series C Note (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K filed June 23, 2003)
  4 .12*    —   Form of Series D Note
  10 .1    —   Credit Agreement, dated as of October 29, 2004, by and among NRP (Operating) LLC, as Borrower, Citibank, N.A., as Administrative Agent, the Banks and WBRD LLC and ACIN LLC, as Guarantors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465)
  10 .2    —   First Amendment to Credit Agreement, dated November 9, 2005 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K, filed on November 10, 2005, File No. 00-1-31465)


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Exhibit
       
Number
     
Description
 
  10 .3    —   Contribution, Conveyance and Assumption Agreement by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Ark Land Company, WPP LLC, GNP LLC, NNG LLC, ACIN LLC, Robertson Coal Management LLC, NRP (Operating) LLC, GP Natural Resource Partners LLC, NRP (GP) LP and Natural Resource Partners L.P., dated as of October 17, 2002 (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10 .4    —   Natural Resource Partners Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465)
  10 .5    —   First Amendment to the Natural Resource Partners Long-Term Incentive Plan dated December 8, 2003 (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465)
  10 .6    —   Second Amendment to the Natural Resource Partners Long-Term Incentive Plan (incorporated by reference to the Current Report on Form 8-K, filed on December 13, 2004)
  10 .7    —   Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465)
  10 .8    —   Natural Resource Partners Annual Incentive Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10 .9    —   Omnibus Agreement dated October 17, 2002, by and among Arch Coal, Inc., Ark Land Company, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10 .10    —   Restricted Business Contribution Agreement, dated January 4, 2007, by and among Christopher Cline, Foresight Reserves LP, Adena Minerals, LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 4, 2007)
  10 .11    —   Investor Rights Agreement, dated January 4, 2007, by and among NRP (GP) LP, GP Natural Resource Partners LLC, Robertson Coal Management and Adena Minerals, LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 4, 2007)
  10 .12    —   Form of Coal Mining Lease between Alpha Natural Resources, LLC and WPP LLC (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465)
  10 .13    —   Purchase and Sale Agreement by and between Steelhead Development Company, LLC and ACIN LLC, dated as of May 31, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 1, 2005)
  10 .14    —   Assignment, Waiver and Amendment Agreement, dated January 20, 2006, by and among Williamson Development Company, LLC, ACIN LLC and WPP LLC
  10 .15    —   Memorandum of Understanding by and between NRP (Operating) LLC and Sedgman USA, LLC, dated as of August 23, 2006 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 24, 2006)
  10 .16    —   Purchase and Sale Agreement, dated as of November 24, 2006, by and between NRP (Operating) LLC and The Andrew W. Mellon Foundation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 27, 2006)
  21 .1*    —   List of subsidiaries of Natural Resource Partners L.P.
  23 .1*    —   Consent of Ernst & Young LLP
  31 .1*    —   Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley
  31 .2*    —   Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley
  32 .1**    —   Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350

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Table of Contents

             
Exhibit
       
Number
     
Description
 
  32 .2**    —   Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350
  99 .1*    —   Audited balance sheet of NRP (GP) LP
 
 
Filed herewith
 
** Furnished herewith

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