##### Table of Contents



UNITED
    STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C.
    20549
 FORM 10-K
      þ

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended
    December 31, 2006oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934For 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. Employerincorporation 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 RegisteredCommon Units representing limited
    partnership interests

New York Stock ExchangeSubordinated Units representing
    limited partnership interests

New York Stock Exchange   Securities registered pursuant to Section 12(g) of the
    Act:
  None.
  þ o
  o þ
  þ o
  Regulation S-K Form 10-K Form 10-K. o
    o Large
    Accelerated Filer
    þ Accelerated
    Filer
    o Non-accelerated
    Filer  Rule 12b-2) o þ
      DOCUMENTS INCORPORATED BY REFERENCE.




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##### 



Table of
    Contents
   
 Item



PagePART I1.


Business


31A.


Risk
    Factors


141B.


Unresolved Staff
    Comments


182.


Properties


183.


Legal
    Proceedings


254.


Submission of
    Matters to a Vote of Security Holders


25PART II5.


Market for
    Registrants Common Units, Subordinated Units, Related
    Unitholder Matters and Issuer Purchases of Equity
    Securities


266.


Selected Financial
    Data


287.


Managements
    Discussion and Analysis of Financial Condition and Results of
    Operations


347A.


Quantitative and
    Qualitative Disclosures About Market Risk


488.


Financial
    Statements and Supplementary Data


499.


Changes In and
    Disagreements with Accountants on Accounting and Financial
    Disclosure


649A.


Controls and
    Procedures


649B.


Other
    Information


65PART III10.


Directors and
    Executive Officers of the General Partner and Corporate
    Governance


6611.


Executive
    Compensation


7212.


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


8013.


Certain
    Relationships and Related Transactions, and Director
    Independence


8114.


Principal
    Accountant Fees and Services


88PART IV15.


Exhibits and
    Financial Statement Schedules


91Form of Series D NoteList of SubsidiariesConsent of Ernst & Young LLPCertification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 1350Certification of CFO Pursuant to Section 1350Audited Balance Sheet   1




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Forward-Looking
    Statements
  Form 10-K
       2




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##### Table of Contents



PART I  Item 1.
    Business      Partnership
    Structure and Management
        (304) 522-5757. (713) 751-7507.
  Coal
    Royalty Business
   3




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##### Table of Contents



10-year
          Recent
    Acquisitions
    2007
    Acquisitions
  Dingess-Rum.
  Cline.
 4




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2006
    Acquisitions
  Quadrant.
  Bluestone.
  D.D. Shepherd.
  Red Fox.
  Coal Mountain.
  Williamson Development.
  Allegany County, Maryland.
  Indiana Reserves.
 5




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##### Table of Contents



Coal
    Royalty Revenues, Reserves and Production
    Average Coal RoyaltyCoal Royalty Revenues


Revenue Per TonFor the Years Ended


For the Years EndedDecember 31,


December 31,2006


2005


2004


2006


2005


2004(In thousands)


($ per ton)AreaAppalachiaNorthern

$
10,231


$
11,306


$
7,084


$
1.92


$
1.89


$
1.70Central


100,487



93,008



76,583



3.14



2.84



2.34Southern


20,469



25,089



14,874



3.83



4.01



2.86Total Appalachia


131,187



129,403



98,541



3.07



2.87



2.34Illinois Basin


5,325



4,288



3,852



1.85



1.54



1.23Northern Powder River Basin


11,240



8,446



4,063



1.72



1.46



1.30Total

$
147,752


$
142,137


$
106,456


$
2.84


$
2.65


$
2.20     Production
    and Reserves
  Production For the Year Ended


Proven and Probable Reserves atDecember 31,


December 31, 20062006


2005


2004


Underground


Surface


Total(Tons in thousands)AreaAppalachiaNorthern


5,329



5,977



4,179



399,641



7,804



407,445Central


31,991



32,790



32,702



1,138,728



107,077



1,245,804Southern


5,347



6,263



5,208



159,660



35,987



195,647Total Appalachia


42,667



45,030



42,089



1,698,028



150,868



1,848,896Illinois Basin


2,877



2,781



3,138



103,819



19,194



123,013Northern Powder River Basin


6,548



5,795



3,130







125,323



125,323Total


52,092



53,606



48,357



1,801,848



295,384



2,097,232   Form 10-K
 6




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Sulfur
    Content, Typical Quality and Type of Coal
  Sulfur Content


Typical Quality


Type of CoalLow


Medium


HighCompliance


(less than


(1.0% to


(greater





Heat Content


SulfurArea

Coal(1)


1.0%)


1.5%)


than 1.5%)


Total


(Btu per pound)


(%)


Steam


Metallurgical(2)(Tons in thousands)


(Tons in thousands)AppalachiaNorthern


43,300



51,879



25,824



329,742



407,445



13,083



2.77



397,883



9,562Central


598,239



931,001



274,660



40,143



1,245,804



13,042



0.87



791,413



454,391Southern


110,795



141,531



41,891



12,224



195,647



13,635



0.90



147,753



47,894Total Appalachia


752,333



1,124,412



342,375



382,110



1,848,896











1,337,049



511,847Illinois 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.    
    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.   7




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Coal
    Transportation and Processing Revenues
        Aggregates
    Royalty Revenues, Reserves and Production
    Oil, Gas
    and Timber Properties
    Significant
    Customers
    Competition
   8




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Regulation
    and Environmental Matters
  General.
      Air Emissions.
   9




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cap-and-trade
  cap-and-trade
        Carbon Dioxide Emissions.
   10




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##### Table of Contents



cap-and-trade
    Surface Mining Control and Reclamation Act of
    1977.
  Hazardous Materials and Waste.
    Water Discharges.
  Ohio Valley Environmental Coalition v. Bulen
 11




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Mine Health and Safety Laws.
      Mining Permits and Approvals.
   12




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Employees
    and Labor Relations
  sub-lessees
  Segment
    Information
    Website
    Access To Company Reports
  www.nrplp.com. Form 10-K, Form 10-Q, Form 8-K
 13




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##### Table of Contents



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 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.    
    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.    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.
   14




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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 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.    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.
    Fluctuations
    in transportation costs and the availability or reliability of
    transportation could reduce the production of coal mined from
    our properties.
     15




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Our
    lessees coal mining operations are subject to operating
    risks that could result in lower coal royalty revenues to
    us.
    
    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.    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.
      If our
    lessees do not manage their operations well, their production
    volumes and our coal royalty revenues could
    decrease.
    
    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; 16




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##### Table of Contents




    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.    Any
    decrease in the demand for metallurgical coal could result in
    lower coal production by our lessees, which would reduce our
    coal royalty revenues.
    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.
    Our
    reserve estimates depend on many assumptions that may be
    inaccurate, which could materially adversely affect the
    quantities and value of our reserves.
    
    future coal prices, operating costs, capital expenditures,
    severance and excise taxes, and development and reclamation
    costs; 17




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##### Table of Contents




    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.    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.
    Item 1B.
    Unresolved
    Staff Comments    Item 2.
    Properties  Major
    Coal Properties
    Northern
    Appalachia
  AFG-Southwest PA.
  Kingwood.
  Sincell.
  Gatling.
    18




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Central
    Appalachia
  D.D. Shepard.
  VICC/Alpha.
 19




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Lynch.
  Pinnacle Property.
  Lone Mountain.
  Pardee.
  VICC/Kentucky Land.
  Dingess-Rum.
 20




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21




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Southern
    Appalachia
  BLC Properties.
     
 22




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##### Table of Contents



Illinois
    Basin
  Hocking-Wolford/Cummings.
  Sato.
  Williamson Development.
    
  Northern
    Powder River Basin
  Western Energy. four-unit
 23




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Title to
    Property
  rights-of-way,
   24




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Item 3.
    Legal
    Proceedings    Item 4.
    Submission
    of Matters to a Vote of Security Holders   25




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##### Table of Contents



PART II  Item 5.
    Market
    for Registrants Common and Subordinated Units, Related
    Unitholder Matters and Issuer Purchases of Equity
    Securities      Price Range


CashNRP

High


Low


Distributions2005First Quarter

$
63.14


$
48.00


$
0.6875Second Quarter

$
61.05


$
49.00


$
0.7125Third Quarter

$
68.95


$
56.78


$
0.7375Fourth Quarter

$
62.70


$
49.47


$
0.76252006First Quarter

$
57.16


$
50.50


$
0.7900Second Quarter

$
58.95


$
51.20


$
0.8200Third Quarter

$
59.20


$
48.20


$
0.8500Fourth Quarter

$
59.98


$
49.50


$
0.8800       Price Range


CashNSP

High


Low


Distributions2005Third Quarter (from
    August 10, 2005)

$
59.20


$
51.22


$
0.7375Fourth Quarter

$
57.95


$
47.70


$
0.76252006First Quarter

$
55.40


$
48.30


$
0.7900Second Quarter

$
56.40


$
48.80


$
0.8200Third Quarter

$
56.75


$
47.56


$
0.8500Fourth Quarter

$
58.89


$
48.40


$
0.8800    26




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##### Table of Contents



1 3
      Percentage
    Allocations of Available Cash From Operating Surplus
  Marginal Percentage Interest inDistributionsHolders ofTotal Quarterly







IncentiveDistribution Target




General


DistributionAmount

Unitholders


Partner


RightsMinimum 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
%    27




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Item 6.
    Selected
    Financial Data  SELECTED
    HISTORICAL FINANCIAL DATA
     28




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  Fromcommencementof operations(October 17, 2002)throughFor 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


$
11,532Aggregate 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



1,047Minimums recognized as revenue


2,082



1,709



1,763



2,033



872Override royalties


957



2,144



3,222



1,022



226Other


7,701



3,367



2,735



1,897



216Total revenues


170,673



159,053



121,432



85,466



13,893Expenses:Depreciation, depletion and
    amortization


29,695



33,730



30,077



24,483



4,526General and administrative


15,520



12,319



11,503



8,923



1,059Property, franchise and other taxes


8,122



8,142



6,835



5,810



1,296Coal royalty and override payments


1,560



3,392



2,045



1,299



397Total expenses


54,897



57,583



50,460



40,515



7,278Income from operations


115,776



101,470



70,972



44,951



6,615Interest 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


$
6,415Balance Sheet Data (at period end):Total assets

$
939,493


$
684,996


$
599,926


$
531,676


$
392,719Deferred revenue


20,654



14,851



15,847



15,054



13,252Long-term debt


454,291



221,950



156,300



192,650



57,500Total liabilities


503,806



259,088



190,734



223,518



74,085Partners capital


435,687



425,908



409,192



308,158



318,634Cash Flow Data:Net cash flow provided by (used
    in):Operating activities

$
138,843


$
121,675


$
90,847


$
64,528


$
6,738Investing activities


(257,714
)


(105,702
)


(77,733
)


(142,511
)


(57,449
)Financing activities


137,224



(10,385
)


4,669



94,550



58,463Other Data:Royalty coal tons produced by
    lessees


52,092



53,606



48,357



44,344



7,314Average gross coal royalty per ton

$
2.84


$
2.65


$
2.20


$
1.66


$
1.58Aggregate 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


$
0.28Subordinated

$
3.48


$
3.39


$
2.29


$
1.59


$
0.28Weighted average number of units
    outstanding:Common


17,183



14,345



13,447



11,354



11,354Subordinated


8,158



10,996



11,354



11,354



11,354Distributions per limited partner
    unit:Common

$
3.340


$
2.9000


$
2.4750


$
2.1450


$
0.4234Subordinated

$
3.340


$
2.9000


$
2.4750


$
2.1450


$
0.4234  29




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WESTERN
    POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
  For thePeriod FromJanuary 1, throughOctober 16, 2002(1)(In thousands,except per ton data)Income Statement Data:Revenues:Coal royalties

$
17,261Timber royalties


2,774Gain on sale of property


92Property taxes


1,221Other


1,219Total revenues


22,567Expenses:General and administrative


2,291Taxes other than income


1,438Depreciation, depletion and
    amortization


3,544Total expenses


7,273Income from operations


15,294Other income (expense):Interest expense


(4,786
)Interest income


114Reversionary interest


(561
)Net income

$
10,061Cash Flow Data:Net cash flow provided by (used
    in):Operating activities

$
8,676Investing activities


(35,028
)Financing activities


27,899Other Data:Royalty coal tons produced by
    lessees


9,572Average gross coal royalty per ton

$
1.80     (1)
    
    Up to the date of contribution of assets to Natural Resource
    Partners L.P. 30




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GREAT
    NORTHERN PROPERTIES LIMITED PARTNERSHIP
  For theperiod fromJanuary 1 throughOctober 16, 2002(1)(In thousands,except per ton data)Income Statement Data:Revenues:Coal royalties

$
5,895Lease and easement income


474Gain on sale of property


Property taxes


61Other


71Total revenues


6,501Expenses:General and administrative


417Taxes other than income


69Depreciation, depletion and
    amortization


1,979Total expenses


2,465Income from operations


4,036Other income (expense):Interest expense


(1,877
)Interest income


115Net income

$
2,274Cash Flow Data:Net cash flow provided by (used
    in):Operating activities

$
3,725Investing activities


Financing activities


(4,069
)Other Data:Royalty coal tons produced by
    lessees


4,970Average gross coal royalty per ton

$
1.19     (1)
    
    Up to the date of contribution of assets to Natural Resource
    Partners L.P. 31




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NEW
    GAULEY COAL CORPORATION
  For theperiod fromJanuary 1 throughOctober 16, 2002(1)(In thousands,except per ton data)Income Statement Data:Revenues:Coal royalties

$
1,434Gain on sale of property


Property taxes


20Other


53Total revenues


1,507Expenses:General and administrative


52Taxes other than income


42Depreciation, depletion and
    amortization


138Total expenses


232Income from operations


1,275Other income (expense):Interest expense


(97
)Interest income


24Reversionary interest


(104
)Net income

$
1,098Cash Flow Data:Net cash flow provided by (used
    in):Operating activities

$
867Investing activities


Financing activities


(474
)Other Data:Royalty coal tons produced by
    lessees


479Average gross coal royalty per ton

$
2.99     (1)
    
    Up to the date of contribution of assets to Natural Resource
    Partners L.P. 32




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##### Table of Contents



ARCH COAL
    CONTRIBUTED PROPERTIES
  For theperiod fromJanuary 1 throughOctober 16, 2002(1)(In thousands,except per ton data)Income Statement Data:Revenues:Coal royalties

$
14,768Other royalties


1,349Property taxes


1,179Total revenues


17,296Direct costs and expenses:Depletion


4,889Property taxes


1,179Other expense


528Total expenses


6,596Excess (deficit) of revenues over
    direct costs and expenses

$
10,700Cash Flow Data:Direct cash flow from contributed
    properties

$
15,181Other Data:Royalty coal tons produced by
    lessees


8,791Average gross coal royalty per ton

$
1.68     (1)
    
    Up to the date of contribution of assets to Natural Resource
    Partners L.P. 33




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##### Table of Contents



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
           34




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##### Table of Contents



Reconciliation
    of GAAP Net cash provided by operating activities
    to Non-GAAP Distributable cash flow
  For the Years EndedDecember 31,2006


2005


2004Cash flow from operations

$
138,843


$
121,675


$
90,847Less 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



9,400Distributable cash flow

$
129,293


$
112,325


$
81,497   Acquisitions
  Recent
    Acquisitions
    2007
    Acquisitions
  Dingess-Rum.
  Cline.
 35




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##### Table of Contents



2006
    Acquisitions
  Quadrant.
  Bluestone.
  D.D. Shepherd.
  Red Fox.
  Coal Mountain.
  Williamson Development.
  Allegany County, Maryland.
  Indiana Reserves.
  Disposition
  Virginia Timber Properties.
 36




---



##### Table of Contents



Critical
    Accounting Policies
  Coal Royalties.
  Aggregate Royalties.
  Coal Processing Fees.
  Oil and Gas Royalties.
  Depreciation and Depletion. units-of-production
  Impact of
    Adoption of FAS 123R
  Share-Based Payment,
 37




---



##### Table of Contents



38




---



##### Table of Contents



Results
    of Operations
 For the Years EndedDecember 31,2006


2005


2004(In thousands, except per ton data)Revenues:Coal royalties

$
147,752


$
142,137


$
106,456Aggregate royalties


538







Coal processing fees


1,452







Oil and gas royalties


4,220



3,180



1,907Property taxes


5,971



6,516



5,349Minimums recognized as revenue


2,082



1,709



1,763Override royalties


957



2,144



3,222Other


7,701



3,367



2,735Total revenues


170,673



159,053



121,432Expenses:Depreciation, depletion and
    amortization


29,695



33,730



30,077General and administrative


15,520



12,319



11,503Property, franchise and other taxes


8,122



8,142



6,835Coal royalty and override payments


1,560



3,392



2,045Total expenses


54,897



57,583



50,460Income from operations


115,776



101,470



70,972Other income (expense):Interest expense


(16,423
)


(11,044
)


(11,192
)Interest income


2,737



1,413



349Loss on early extinguishment of debt










(1,135
)Net income

$
102,090


$
91,839


$
58,994Other Data:Coal RoyaltiesAppalachiaNorthern

$
10,231


$
11,306


$
7,084Central


100,487



93,008



76,583Southern


20,469



25,089



14,874Total Appalachia


131,187



129,403



98,541Illinois Basin


5,325



4,288



3,852Northern Powder River Basin


11,240



8,446



4,063Total

$
147,752


$
142,137


$
106,456Production (tons)AppalachiaNorthern


5,329



5,977



4,179Central


31,991



32,790



32,702Southern


5,347



6,263



5,208Total Appalachia


42,667



45,030



42,089Illinois Basin


2,877



2,781



3,138Northern Powder River Basin


6,548



5,795



3,130Total


52,092



53,606



48,357Average gross royaltyAppalachiaNorthern

$
1.92


$
1.89


$
1.70Central


3.14



2.84



2.34Southern


3.83



4.01



2.86Total Appalachia


3.07



2.87



2.34Illinois Basin


1.85



1.54



1.23Northern Powder River Basin


1.72



1.46



1.30Total

$
2.84


$
2.65


$
2.20Aggregate RoyaltiesRoyalty revenues

$
538







Production


412







Average gross royalty

$
1.33







  39




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##### Table of Contents



Year
    ended December 31, 2006 compared with year ended
    December 31, 2005
  Revenues.
    Appalachia.
    
    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.    
    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. 40




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##### Table of Contents




    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.    
    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.
  
    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.
  Other revenues.
 41




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##### Table of Contents



Operating costs and expenses.
  
    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.
  Year
    ended December 31, 2005 compared to year ended
    December 31, 2004
  Revenues.
  Coal royalty revenues.
        
    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. 42




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##### Table of Contents




    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.      
    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.    
    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. 43




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##### Table of Contents



Expenses.
  
    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).
  Related
    Party Transactions
  Partnership
    Agreement
    The
    Cline Group
   44




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##### Table of Contents



Second Contribution Agreement.
  Restricted Business Contribution Agreement.
  Investor Rights Agreement.
  Quintana
    Energy Partners, L.P.
  Form 10-K.
   45




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##### Table of Contents



Liquidity
    and Capital Resources
  Cash
    Flows and Capital Expenditures
          Contractual
    Obligations and Commercial Commitments
    
    $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.    
    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 46




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##### Table of Contents




    at a rate equal to LIBOR plus an applicable margin ranging from
    .75% to 2.00%.      
    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.
    
    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.    Payments Due by Period(1)Contractual Obligations

Total


2007


2008


2009


2010


2011


ThereafterLong-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
     47




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##### Table of Contents



Off-Balance
    Sheet Transactions
    Inflation
    Environmental
    Item 7A.
    Quantitative
    and Qualitative Disclosures about Market Risk    Commodity
    Price Risk
    Interest
    Rate Risk
   48




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##### Table of Contents



Item 8.
    Financial
    Statements and Supplementary Data  INDEX TO
    FINANCIAL STATEMENTS
  PageReport of
    independent registered public accounting firm


50Balance sheets as
    of December 31, 2006, and 2005


51Income statements
    for the years ended December 31, 2006, 2005, and
    2004


52Statements of
    partners capital for the years ended December 31,
    2006, 2005, and 2004


53Statements of cash
    flows for the years ended December 31, 2006, 2005, and
    2004


54Notes to financial
    statements


55  49




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  CONSOLDATED
    FINANCIAL STATEMENTS
  REPORT
    OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
               Ernst & Young
     50




---



##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  CONSOLIDATED
    BALANCE SHEETS
  December 31,


December 31,2006


2005(In thousands, exceptfor unit information)ASSETSCurrent assets:Cash and cash equivalents

$
66,044


$
47,691Accounts receivable, net of
    allowance for doubtful accounts


23,357



21,946Accounts receivable 
    affiliate


21



6Other


1,411



833Total current assets


90,833



70,476Land


17,781



14,123Plant and equipment, net


29,615



5,924Coal and other mineral rights, net


798,135



590,459Loan financing costs, net


2,197



2,431Other assets, net


932



1,583Total assets

$
939,493


$
684,996LIABILITIES AND PARTNERS
    CAPITALCurrent liabilities:Accounts payable and accrued
    liabilities

$
1,041


$
677Accounts payable 
    affiliate


105



88Current portion of long-term debt


9,542



9,350Accrued incentive plan
    expenses  current portion


5,418



1,105Property, franchise and other
    taxes payable


4,330



4,138Accrued interest


3,846



1,534Total current liabilities


24,282



16,892Deferred revenue


20,654



14,851Accrued incentive plan expenses


4,579



5,395Long-term debt


454,291



221,950Partners capital:Common units (outstanding:
    19,663,715 in 2006, 16,825,307 in 2005)


338,912



292,990Subordinated units (outstanding:
    5,676,817 in 2006, 8,515,228 in 2005)


83,772



123,114General partners interest


12,138



10,024Holders of incentive distribution
    rights


1,616



582Accumulated other comprehensive
    loss


(751
)


(802
)Total partners capital


435,687



425,908Total liabilities and
    partners capital

$
939,493


$
684,996    51




---



##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  CONSOLIDATED
    STATEMENTS OF INCOME
  For the Years EndedDecember 31,2006


2005


2004(In thousands, except per unit data)Revenues:Coal royalties

$
147,752


$
142,137


$
106,456Aggregate royalties


538







Coal processing fees


1,452







Oil and gas royalties


4,220



3,180



1,907Property taxes


5,971



6,516



5,349Minimums recognized as revenue


2,082



1,709



1,763Override royalties


957



2,144



3,222Other


7,701



3,367



2,735Total revenues


170,673



159,053



121,432Operating costs and expenses:Depreciation, depletion and
    amortization


29,695



33,730



30,077General and administrative


15,520



12,319



11,503Property, franchise and other taxes


8,122



8,142



6,835Coal royalty and override payments


1,560



3,392



2,045Total operating costs and expenses


54,897



57,583



50,460Income from operations


115,776



101,470



70,972Other income (expense)Interest expense


(16,423
)


(11,044
)


(11,192
)Interest income


2,737



1,413



349Loss on early extinguishment of
    debt










(1,135
)Net income

$
102,090


$
91,839


$
58,994Net income attributable to:(1)General partner

$
9,717


$
4,491


$
1,705Holders of incentive distribution
    rights

$
4,133


$
1,429


$
281Limited partners

$
88,240


$
85,919


$
57,008Basic and diluted net income per
    limited partner unit:Common

$
3.48


$
3.39


$
2.29Subordinated

$
3.48


$
3.39


$
2.29Weighted average number of units
    outstanding:Common


17,183



14,345



13,447Subordinated


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.   52




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  STATEMENT
    OF PARTNERS CAPITAL
  Holdersof Incentive


AccumulatedGeneral


Distribution


OtherCommon Units


Subordinated Units


Partner


Rights


ComprehensiveUnits


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
)

$
308,158Issuance of units to the public,
    net of offering and other costs


5,250,000



200,355























200,355Redemption of common units, net


(2,616,752
)


(100,121
)






















(100,121
)Additional contribution by the
    General Partner


















2,147











2,147Distributions 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







58,994Loss on interest hedge


























52



52Comprehensive income


























52



59,046Balance at December 31, 2004


13,986,906


$
243,814



11,353,658


$
157,324


$
8,802


$
105


$
(853
)

$
409,192Subordinated 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







91,839Loss on interest hedge


























51



51Comprehensive income


























51



91,890Balance at December 31, 2005


16,825,307


$
292,990



8,515,228


$
123,114


$
10,024


$
582


$
(802
)

$
425,908Subordinated 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







102,090Loss on interest hedge


























51



51Comprehensive income


























51



102,141Balance at December 31, 2006


19,663,715


$
338,912



5,676,817


$
83,772


$
12,138


$
1,616


$
(751
)

$
435,687    53




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  CONSOLIDATED
    STATEMENTS OF CASH FLOWS
  For the Years EndedDecember 31,2006


2005


2004(In thousands)Cash flows from operating
    activities:Net income

$
102,090


$
91,839


$
58,994Adjustments to reconcile net income
    to net cash provided by operating activities:Depreciation, depletion and
    amortization


29,695



33,730



30,077Non-cash interest charge


349



318



932Loss on early extinguishment of debt










1,135Gain 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
)


236Accounts payable and accrued
    liabilities


381



84



(47
)Accrued interest


2,312



1,268



(415
)Deferred revenue


5,803



(996
)


793Accrued incentive plan expenses


3,497



1,670



2,574Property, franchise and other taxes
    payable


192



678



661Net cash provided by operating
    activities


138,843



121,675



90,847Cash 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



75,500Deferred 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










2,147Proceeds from sale of 5,250,000
    common units, net of transaction costs










200,355Redemption 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
)


4,669Net increase in cash


18,353



5,588



17,783Cash at beginning of period


47,691



42,103



24,320Cash at end of period

$
66,044


$
47,691


$
42,103Supplemental cash flow information:Cash paid during the period for
    interest

$
13,734


$
9,459


$
10,603Non-cash financing activities:Utility improvement obligation
    acquired

$
2,883







    54




---



##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.



NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS  1.
    Basis of
    Presentation and Organization      2.
    Summary
    of Significant Accounting Policies  Principles
    of Consolidation
    Reclassification
    Use of
    Estimates
    Cash
    Equivalents
    Accounts
    Receivable
   55




---



##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Land,
    Coal and Mineral Rights
  unit-of-production
  Plant
    and Equipment
    Asset
    Impairment
    Concentration
    of Credit Risk
    Fair
    Value of Financial Instruments
      Deferred
    Financing Costs
    Revenues
  Coal Royalties.
 56




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Aggregate Royalties.
  Coal Processing Fees.
  Minimum Royalties.
  Oil and Gas Royalties.
  Property
    Taxes
    Income
    Taxes
    Share-Based
    Payment
  Share-Based Payment,
 57




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    3.
    Allowance
    for Doubtful Accounts    2006


2005


2004(In thousands)Balance, January 1

$
85


$
185


$
306Provision 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    December 31,


December 31,2006


2005(In thousands)Plant and equipment at cost

$
30,266


$
6,019Less accumulated depreciation


(651
)


(95
)Net book value

$
29,615


$
5,924   For the Years EndedDecember 31,2006


2005


2004(In thousands)Total depreciation expense on
    plant and equipment

$
556


$
95


$
   5.
    Coal and
    Other Mineral Rights    December 31,


December 31,2006


2005(In thousands)Coal and other mineral rights

$
970,342


$
734,242Less accumulated depletion and
    amortization


(172,207
)


(143,783
)Net book value

$
798,135


$
590,459  58




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  For the Years EndedDecember 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    December 31,


December 31,2006


2005(In thousands)$300 million floating rate
    revolving credit facility, due October 2010

$
214,000


$
25,0005.55% senior notes, with
    semi-annual interest payments in June and December, with annual
    principal payments in June, maturing in June 2023


50,100



53,4004.91% senior notes, with
    semi-annual interest payments in June and December, with annual
    principal payments in June, maturing in June 2018


61,850



67,9005.55% senior notes, with
    semi-annual interest payments in June and December, maturing
    June 2013


35,000



35,0005.05% senior notes, with
    semi-annual interest payments in January and July, with
    scheduled principal payments beginning July 2008, maturing in
    July 2020


100,000



50,0005.31% utility local improvement
    obligation, with annual principal and interest payments,
    maturing in March 2021


2,883



Total debt


463,833



231,300Less  current portion
    of long term debt


(9,542
)


(9,350
)Long-term debt

$
454,291


$
221,950     2007

$
9,5422008


17,2342009


17,2342010


231,2342011


17,234Thereafter


171,355$
463,833     
    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%. 59




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
       
    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.        7.
    Net
    Income Per Unit Attributable to Limited Partners    8.
    Related
    Party Transactions     60




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   9.
    Commitments
    and Contingencies  Legal
    Environmental
    Compliance
    10.
    Major
    Lessees    For the Years Ended December 31,2006


2005


2004(Dollars in thousands)Revenues


Percent


Revenues


Percent


Revenues


PercentLessee 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     61




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
      Outstanding grants at the
    beginning of the period


211,931Grants during the period


61,166Grants vested and paid during the
    period


(13,947
)Forfeitures during the period


(1,540
)Outstanding grants at the end of
    the period


257,610     12.
    Subsequent
    Events (Unaudited)  Acquisitions
  Cline.
  Dingess-Rum.
  Distributions
   62




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  13.
    Supplemental
    Financial Data  Selected
    Quarterly Financial Information
    (Unaudited)
  First


Second


Third


Fourth2006

Quarter


Quarter


Quarter


Quarter(In thousands, except per unit data)Total revenues

$
46,528


$
40,982


$
41,491


$
41,672Income from operations


31,624



27,964



28,569



27,619Net income

$
28,524


$
25,044


$
25,274


$
23,248Basic and diluted net income per
    limited partner unit:Common

$
1.01


$
0.86


$
0.85


$
0.76Subordinated

$
1.01


$
0.86


$
0.85


$
0.76Weighted average number of units
    outstanding, Basic and diluted:Common


16,825



16,825



16,825



18,245Subordinated


8,515



8,515



8,515



7,096   First


Second


Third


Fourth2005

Quarter


Quarter


Quarter


QuarterTotal revenues

$
36,247


$
41,697


$
38,735


$
42,374Income from operations


22,673



27,211



23,962



27,624Net income

$
20,447


$
24,972


$
21,465


$
24,955Basic and diluted net income per
    limited partner unit:Common

$
0.77


$
0.92


$
0.79


$
0.91Subordinated

$
0.77


$
0.92


$
0.79


$
0.91Weighted average number of units
    outstanding, Basic and diluted:Common


13,987



13,987



13,987



15,407Subordinated


11,354



11,354



11,354



9,934   First


Second


Third


Fourth2004

Quarter


Quarter


Quarter


QuarterTotal revenues

$
26,362


$
29,497


$
34,221


$
31,352Income from operations


14,537



17,751



21,984



16,700Net income

$
11,174


$
15,128


$
19,368


$
13,324Basic and diluted net income per
    limited partner unit:Common

$
0.47


$
0.58


$
0.74


$
0.50Subordinated

$
0.47


$
0.58


$
0.74


$
0.50Weighted average number of units
    outstanding, Basic and diluted:Common


11,816



13,987



13,987



13,987Subordinated


11,354



11,354



11,354



11,354  63




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##### Table of Contents



Item 9.
    Changes
    In and Disagreements with Accountants on Accounting and
    Financial Disclosure    Item 9A.
    Controls
    and Procedures  Evaluation
    of Disclosure Controls and Procedures
  Rule 13a-15(e)
  Managements
    Report on Internal Control Over Financial Reporting
  Rules 13a-15(f) 15d-15(f).
    Attestation
    Report of Independent Registered Public Accounting
    Firm
         64




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##### Table of Contents



Ernst &
    Young
     Item 9B.
    Other
    Information   65




---



##### Table of Contents



PART III  Item 10.
    Directors
    and Executive Officers of the Managing General Partner and
    Corporate Governance    Name

Age


Position with the Managing General PartnerCorbin J. Robertson, Jr.


59


Chairman of the Board and Chief
    Executive OfficerNick Carter


60


President and Chief Operating
    OfficerDwight L. Dunlap


53


Chief Financial Officer and
    TreasurerKevin F. Wall


50


Vice President and Chief EngineerKathy E. Hager


55


Vice President Investor RelationsWyatt L. Hogan


35


Vice President, General Counsel
    and SecretaryKevin J. Craig


38


Vice President, Business
    DevelopmentKenneth Hudson


52


ControllerRobert T. Blakely


65


DirectorDavid M. Carmichael


68


DirectorJ. Matthew Fifield


33


DirectorRobert B. Karn III


65


DirectorS. Reed Morian


60


DirectorW. W. Scott, Jr.


61


DirectorStephen P. Smith


45


Director   Corbin J. Robertson, Jr.
  Nick Carter
  Dwight L. Dunlap
 66




---



##### Table of Contents



Kevin F. Wall
  Kathy E. Hager
  Wyatt L. Hogan
  Kevin J. Craig
  Kenneth Hudson
  Robert T. Blakely
  David M. Carmichael
 67




---



##### Table of Contents



J. Matthew Fifield
  Robert B. Karn III
  S. Reed Morian
  W. W. Scott, Jr.
  Stephen P. Smith
  Corporate
    Governance
  Board
    Attendance and Executive Sessions
   68




---



##### Table of Contents



Independence
    of Directors
  Regulation S-K.
  Report
    of the Audit Committee
            Form 10-Q Form 10-K
 69




---



##### Table of Contents



Form 10-K
       Compensation,
    Nominating and Goverance Committee Authority
  Form 10-K.
  
    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.      Report
    of the Compensation, Nominating and Governance
    Committee
  Regulation S-K Form 10-K
      Section 16(a)
    Beneficial Ownership Reporting Compliance
   70




---



##### Table of Contents



Partnership
    Agreement
  www.nrplp.com.
  Corporate
    Governance Guidelines and Code of Business Conduct and
    Ethics
  Regulation S-K. www.nrplp.com
  NYSE
    Certification
   71




---



##### Table of Contents



Item 11.
    Executive
    Compensation  Compensation
    Discussion and Analysis
  Overview
  Form 10-K.
  Executive
    Officer Compensation Strategy and Philosophy
      
    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.       72




---



##### Table of Contents



20-day
    Role
    of Compensation Experts
  Form 10-K.
  Role
    of Our Executive Officers in the Compensation
    Process
    Components
    of Compensation
  Base
    Salaries
    Annual
    Cash Incentive Awards
   73




---



##### Table of Contents



Long-Term
    Incentive Compensation
    2003-2006,
  Perquisites
    and Other Personal Benefits
        Unit
    Ownership Requirements
   74




---



##### Table of Contents



Securities
    Trading Policy
    Tax
    Implications of Executive Compensation
    Accounting
    Implications of Executive Compensation
  book-up
  Share-Based Payment,
 75




---



##### Table of Contents



Summary
    Compensation Table
    Change inPension ValueNon-Equity


and Non-QualifiedPhantom





Incentive


DeferredUnit


Option


Plan


Compensation


All OtherName and Principal




Salary


Bonus


Awards(1)


Awards


Compensation


Earnings


Compensation(2)


TotalPosition

Year


($)


($)


($)


($)


($)


($)


($)


($)Corbin J. Robertson, Jr.
    Chairman and CEO


2006











899,387















74,857



974,244Dwight L. Dunlap
    CFO and Treasurer


2006



176,908



100,000



298,926















86,164



661,998Nick Carter
    President and COO


2006



261,900



200,000



449,683















110,973



1,022,556Wyatt L. Hogan
    Vice President, General
    Counsel and Secretary


2006



174,018



60,000



183,384















79,632



497,034Kevin 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 OtherUnit Awards:


Grant Date FairNumber of


Value ofPhantom Units(1)


Unit Awards(2)Named Executive Officer

Grant Date


(#)


($)Corbin J. Robertson, Jr.


2/13/2006



10,000



621,200Dwight L. Dunlap


2/13/2006



3,500



217,420Nick Carter


2/13/2006



5,000



310,600Wyatt L. Hogan


2/13/2006



2,900



180,148Kevin 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.  Form 10-K
 76




---



##### Table of Contents



Outstanding
    Awards at December 31, 2006
    Number of


Market ValuePhantom Units That


of Phantom Units ThatHave Not Vested


Have Not Vested(1)Named Executive Officer

(#)


($)Corbin J. Robertson, Jr.(2)


52,365



3,034,552Dwight L. Dunlap(3)


17,457



1,011,633Nick Carter(4)


26,182



1,517,247Wyatt L. Hogan(5)


10,826



627,367Kevin 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. 77




---



##### Table of Contents



Phantom
    Units Vested in 2006
    Number ofPhantom Units That


Value Realized onVested


VestingNamed Executive Officer

(#)


($)Corbin J. Robertson, Jr.(1)


3,667



193,691Dwight L. Dunlap(1)


1,143



60,373Nick Carter(1)


1,833



96,819Wyatt L. Hogan(2)


214



11,997Kevin 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
    Number of


Potential


PotentialPhantom


Post-Employment


Cash PaymentsUnits


Payments


Required UponThat Have


Required Upon


Change inNot Vested


Change in Control


ControlNamed Executive Officer

(#)


($)


($)Corbin J. Robertson, Jr.


52,365







2,935,582Dwight L. Dunlap


17,457







978,639Nick Carter


26,182







1,467,763Wyatt L. Hogan


10,826







606,906Kevin F. Wall


12,836







719,586  78




---



##### Table of Contents



Directors
    Compensation for the Year Ended December 31, 2006
    Change inPension ValueandNonqualifiedFees Earned








Non-Equity


Deferredor Paid in


Phantom


Option


Incentive Plan


Compensation


All OtherCash


Unit Awards(1)(2)


Awards


Compensation


Earnings


Compensation


TotalName

($)


($)


($)


($)


($)


($)


($)Robert Blakely


42,000



92,464



















134,464David Carmichael


44,000



90,569



















134,569J. Matthew Fifield(3)


























Robert Karn III


49,000



90,569



















139,569S. Reed Morian


31,000



90,569



















121,569Stephen Smith


36,000



90,569



















126,569W. 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.     79




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##### Table of Contents



Item 12.
    Security
    Ownership of Certain Beneficial Owners and
    Management    Percentage





Percentage of





Percentage


PercentageCommon


of Common


Subordinated


Subordinated


Class B


of Class B


of TotalName of Beneficial Owner

Units


Units(1)


Units


Units(2)


Units


Units(3)


UnitsCorbin 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. 80




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##### Table of Contents



Item 13.
    Certain
    Relationships and Related Transactions, and Director
    Independence  Distributions
    and Payments to the General Partner and its Affiliates
    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
    
    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 81




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##### Table of Contents




    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.      
    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.           82




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##### Table of Contents



The Cline
    Group
    Second Contribution Agreement.
  Restricted Business Contribution
    Agreement.
 83




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##### Table of Contents



Investor Rights Agreement.
  Quintana Energy Partners, L.P.
  In 2006, Corbin J. Robertson, Jr.
  
    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 84




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##### Table of Contents



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.    Conflicts
    of Interest
        
    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.    
    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.   85




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##### Table of Contents



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.
    
    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.    
    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.      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
    reimburse our general partner and its affiliates for
    expenses.
    Our
    general partner intends to limit its liability regarding our
    obligations.
   86




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##### Table of Contents



Common
    unitholders have no right to enforce obligations of our general
    partner and its affiliates under agreements with
    us.
    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.
        We may
    not choose to retain separate counsel for ourselves or for the
    holders of common units.
    Our
    general partners affiliates may compete with
    us.
    Director
    Independence
   87




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##### Table of Contents



Item 14.
    Principal
    Accountant Fees and Services  out-of-pocket
  2006


2005Audit Fees(1)

$
385,725


$
403,633Audit-Related Fees






Tax Fees(2)

$
400,920


$
274,840All 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    case-by-case
   88




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##### Table of Contents



II.
    Delegation    III.
    Audit
    Services      IV.
    Audit-related
    Services  agreed-upon and/or
 89




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##### Table of Contents



V.
    Tax
    Services    VI.
    Pre-Approval
    Fee Levels or Budgeted Amounts    VII.
    Procedures     90




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##### Table of Contents



PART IV  Item 15.
    Exhibits
    and Financial Statement Schedules  (a)(1) and (2) Financial Statements and Schedules
    (a)(3) Exhibits
  ExhibitNumber



Description2
.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 91




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##### Table of Contents



ExhibitNumber



Description10
.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 LLC10
.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) 92




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##### Table of Contents



ExhibitNumber



Description21
.1*



List of subsidiaries of Natural
    Resource Partners L.P.23
.1*



Consent of Ernst & Young
    LLP31
.1*



Certification of Chief Executive
    Officer pursuant to Section 302 of Sarbanes-Oxley31
.2*



Certification of Chief Financial
    Officer pursuant to Section 302 of Sarbanes-Oxley32
.1**



Certification of Chief Executive
    Officer pursuant to 18 U.S.C. § 135032
.2**



Certification of Chief Financial
    Officer pursuant to 18 U.S.C. § 135099
.1*



Audited balance sheet of NRP (GP)
    LP     *
    
    Filed herewith**
    
    Furnished herewith 93




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##### Table of Contents



SIGNATURES
    NATURAL RESOURCE PARTNERS
    L.P.
  By:
    GP NATURAL RESOURCE    By:
    /s/  Corbin
    J. Robertson, Jr.,   Chairman of the Board and
 Chief Executive Officer
 (Principal Executive Officer)
   By:
    /s/  Dwight
    L. Dunlap   Chief Financial Officer and Treasurer
 (Principal Financial Officer)
   By:
    /s/  Kenneth
    Hudson   Controller
 (Principal Accounting Officer)
   By:
    /s/  Robert
    T. Blakely   Director
   By:
    /s/  David
    M. Carmichael   Director
   By:
    /s/  J.
    Matthew Fifield   Director
   By:
    /s/  Robert
    B. Karn III   Director
   By:
    /s/  S.
    Reed Morian   Director
   By:
    /s/  W.W.
    Scott, Jr.   Director
   By:
    /s/  Stephen
    P. Smith   Director
 94




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##### Table of Contents



Index to
    Exhibits
  ExhibitNumber



Description2
.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 Note10
.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) 95




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##### Table of Contents



ExhibitNumber



Description10
.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 LLC10
.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
    LLP31
.1*



Certification of Chief Executive
    Officer pursuant to Section 302 of Sarbanes-Oxley31
.2*



Certification of Chief Financial
    Officer pursuant to Section 302 of Sarbanes-Oxley32
.1**



Certification of Chief Executive
    Officer pursuant to 18 U.S.C. § 1350 96




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##### Table of Contents



ExhibitNumber



Description32
.2**



Certification of Chief Financial
    Officer pursuant to 18 U.S.C. § 135099
.1*



Audited balance sheet of NRP (GP)
    LP     *
    
    Filed herewith**
    
    Furnished herewith 97