##### 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, 2007 oro

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(State or other jurisdiction
    of
    incorporation or organization)

35-2164875(I.R.S. Employer
    Identification Number)601 Jefferson, Suite 3600
    Houston, Texas(Address of principal
    executive offices)

77002(Zip
    Code)   (713) 751-7507
  (Registrants telephone number, including area code)
  Securities registered pursuant to Section 12(b) of the
    Act:
 Title of Each Class

Name of Each Exchange on Which RegisteredCommon 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
    Large accelerated
    filer þ

Accelerated
    filer o

Non-accelerated
    filer o
    (Do not check if a smaller reporting company)

Smaller Reporting
    company o   Rule 12b-2) o þ
      DOCUMENTS
    INCORPORATED BY REFERENCE.
  None.




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##### 





Table of
    Contents
   
 Item



PagePART I1.


Business


21A.


Risk Factors


131B.


Unresolved Staff Comments


232.


Properties


233.


Legal Proceedings


314.


Submission of Matters to a Vote of Security
    Holders


31PART II5.


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


326.


Selected Financial Data


347.


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


357A.


Quantitative and Qualitative Disclosures About
    Market Risk


488.


Financial Statements and Supplementary Data


509.


Changes In and Disagreements with Accountants on
    Accounting and Financial Disclosure


689A.


Controls and Procedures


689B.


Other Information


69PART III10.


Directors and Executive Officers of the General
    Partner and Corporate Governance


7011.


Executive Compensation


7512.


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


8213.


Certain Relationships and Related Transactions,
    and Director Independence


8414.


Principal Accounting Fees and Services


91PART IV15.


Exhibits, Financial Statement Schedules


94Form of Phantom Unit AgreementList 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 of NRP (GP) LP




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Forward-Looking
    Statements
  Form 10-K
       1




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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
   2




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10-year
          Recent
    Acquisitions
    2007
    Acquisitions
  Massey Energy.
  National Resources.
  Cheyenne Resources.
  Mid-Vol Coal Preparation Plant.
 3




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Mettiki.
  Westmoreland.
  Dingess-Rum.
  Cline.
  2006
    Acquisitions
  Quadrant.
  Bluestone.
  D.D. Shepherd.
  Red Fox.
  Coal Mountain.
  Williamson Development.
  Allegany County, Maryland.
 4




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


Revenue per Tonfor the Years Ended


for the Years EndedDecember 31,


December 31,2007


2006


2005


2007


2006


2005(In thousands)


($ per ton)AreaAppalachiaNorthern

$
16,664


$
10,231


$
11,306


$
2.29


$
1.92


$
1.89Central


117,820



100,487



93,008



3.29



3.14



2.84Southern


17,832



20,469



25,089



3.87



3.83



4.01Total Appalachia


152,316



131,187



129,403



3.19



3.07



2.87Illinois Basin


7,963



5,325



4,288



2.15



1.85



1.54Northern Powder River Basin


11,064



11,240



8,446



1.90



1.72



1.46Total

$
171,343


$
147,752


$
142,137


$
2.99


$
2.84


$
2.65     Production
    and Reserves
  Proven and Probable Reserves atProduction for the Year Ended December 31,


December 31, 20072007


2006


2005


Underground


Surface


Total(Tons in thousands)AreaAppalachiaNorthern


7,270



5,329



5,977



461,641



7,385



469,026Central


35,835



31,991



32,790



1,078,105



153,645



1,231,750Southern


4,603



5,347



6,263



157,879



34,311



192,190Total Appalachia


47,708



42,667



45,030



1,697,625



195,341



1,892,966Illinois Basin


3,709



2,877



2,781



114,731



17,299



132,030Northern Powder River Basin


5,815



6,548



5,795







119,508



119,508Total


57,232



52,092



53,606



1,812,356



332,148



2,144,504    5




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Form 10-K
    Sulfur
    Content, Typical Quality and Type of Coal
  Sulfur ContentLow


Medium


High





Typical Quality


Type of CoalCompliance


(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



24,891



392,256



469,026



13,013



2.74



459,463



9,563Central


662,803



960,816



240,926



30,008



1,231,750



13,355



0.87



808,692



423,058Southern


108,391



139,046



41,215



11,929



192,190



13,639



0.90



145,753



46,437Total Appalachia


814,494



1,151,741



307,032



434,193



1,892,966











1,413,908



479,058Illinois Basin






414



4,319



127,297



132,030



11,792



2.45



132,030



Northern Powder River Basin






119,508











119,508



8,800



0.65



119,508



Total


814,494



1,271,663



311,351



561,490



2,144,504











1,665,446



479,058     (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. 6




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Coal
    Transportation and Processing Revenues
      Aggregates
    Royalty Revenues, Reserves and Production
    Oil and
    Gas Properties
    Significant
    Customers
    Competition
   7




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Regulation
    and Environmental Matters
  General.
      Air Emissions.
   8




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cap-and-trade
  cap-and-trade
        Carbon Dioxide Emissions. -
 9




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cap-and-trade
    Surface Mining Control and Reclamation Act of
    1977.
  Hazardous Materials and Waste.
    Water Discharges.
  Ohio Valley Environmental Coalition v. Bulen
 10




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Ohio Valley Environmental Coalition v. Strock
  Kentucky Waterways Alliance,
    Inc. v. United States Army Corps of Engineers, No. 3:07-cv-00677
  See The West Virginia Highlands Conservancy,
    Plaintiff, v. Dirk Kempthorne, Secretary of the Department
    of the Interior, et al., Defendants, and the West Virginia Coal
    Association, Intervenor/Defendan No. 2:00-cv-1062
   11




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




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Employees
    and Labor Relations
    Segment
    Information
    Website
    Access To Company Reports
  www.nrplp.com Form 10-K, Form 10-Q, Form 8-K
  Item 1A.
    Risk
    Factors  Risks
    Related to 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.
      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;
    global economic conditions;
    domestic and foreign governmental regulations and taxes; 13




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
    the price and availability of alternative fuels;
    the proximity to and capacity of transportation facilities;
    weather conditions; and
    the effect of worldwide energy conservation measures.    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.
    Massachusetts v. Environmental
    Protection Agency
  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; 14




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
    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;
    expansion plans and capital expenditures
    credit risk of their customers;
    permitting;
    insurance and surety bonding;
    acquisition of surface rights and other mineral estates;
    employee wages;
    coal transportation arrangements; 15




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
    compliance with applicable laws, including environmental
    laws; and
    mine closure and reclamation.    Fluctuations
    in transportation costs and the availability or reliability of
    transportation could reduce the production of coal mined from
    our properties.
      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.
   16




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Our
    growing coal infrastructure business exposes us to risks that we
    have not experienced in the royalty business.
    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;
    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.
    Risks
    Inherent in an Investment in Natural Resource Partners
    L.P.
  Cash
    distributions are not guaranteed and may fluctuate with our
    performance and the establishment of financial
    reserves.
   17




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Cost
    reimbursements due to our general partner may be substantial and
    will reduce our cash available for distribution to
    unitholders.
    Unitholders
    may not be able to remove our general partner even if they wish
    to do so.
    2 3
    
    generally, if a person acquires 20% or more of any class of
    units then outstanding other than from our general partner or
    its affiliates, the units owned by such person cannot be voted
    on any matter; and
    limitations upon the ability of unitholders to call meetings or
    to acquire information about our operations, as well as other
    limitations upon the unitholders ability to influence the
    manner or direction of management.    We may
    issue additional common units without unitholder approval, which
    would dilute a unitholders existing ownership
    interests.
    
    an existing unitholders proportionate ownership interest
    in NRP will decrease;
    the amount of cash available for distribution on each unit may
    decrease;
    the relative voting strength of each previously outstanding unit
    may be diminished; and
    the market price of the common units may decline.  Our
    general partner has a limited call right that may require
    unitholders to sell their units at an undesirable time or
    price.
   18




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Unitholders
    may not have limited liability if a court finds that unitholder
    actions constitute control of our business.
      Section 17-607
  Conflicts
    of interest could arise among our general partner and us or the
    unitholders.
    
    we do not have any employees and we rely solely on employees of
    affiliates of the general partner;
    under our partnership agreement, we reimburse the general
    partner for the costs of managing and for operating the
    partnership;
    the amount of cash expenditures, borrowings and reserves in any
    quarter may affect cash available to pay quarterly distributions
    to unitholders;
    the general partner tries to avoid being liable for partnership
    obligations. The general partner is permitted to protect its
    assets in this manner by our partnership agreement. Under our
    partnership agreement the general partner would not breach its
    fiduciary duty by avoiding liability for partnership obligations
    even if we can obtain more favorable terms without limiting the
    general partners liability; under our partnership
    agreement, the general partner may pay its affiliates for any
    services rendered on terms fair and reasonable to us. The
    general partner may also enter into additional contracts with
    any of its affiliates on behalf of us. Agreements or contracts
    between us and our general partner (and its affiliates) are not
    necessarily the result of arms length negotiations; and
    the general partner would not breach our partnership agreement
    by exercising its call rights to purchase limited partnership
    interests or by assigning its call rights to one of its
    affiliates or to us.  The
    control of our general partner may be transferred to a third
    party without unitholder consent. A change of control may result
    in defaults under certain of our debt instruments and the
    triggering of payment obligations under compensation
    arrangements.
    and/or
 19




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Tax Risks
    to Common Unitholders
  Our
    tax treatment depends on our status as a partnership for federal
    income tax purposes as well as our not being subject to a
    material amount of entity-level taxation by individual states.
    If the IRS were to treat us as a corporation for federal income
    tax purposes or we were to become subject to additional amounts
    of entity-level taxation for state tax purposes, then our cash
    available for distribution to you would be substantially
    reduced.
            If the
    IRS contests the federal income tax positions we take, the
    market for our common units may be adversely impacted and the
    cost of any IRS contest will reduce our cash available for
    distribution to you.
   20




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You
    will be required to pay taxes on your share of our income even
    if you do not receive any cash distributions from
    us.
    Tax
    gain or loss on the disposition of our common units could be
    more or less than expected.
    Tax-exempt
    entities and
    non-U.S.
    persons face unique tax issues from owning our common units that
    may result in adverse tax consequences to them.
  non-U.S. persons non-U.S. persons non-U.S. persons non-U.S. person,
  We
    will treat each purchaser of common units as having the same tax
    benefits without regard to the actual common units purchased.
    The IRS may challenge this treatment, which could adversely
    affect the value of the common units.
    We
    prorate our items of income, gain, loss and deduction between
    transferors and transferees of our units each month based upon
    the ownership of our units on the first day of each month,
    instead of on the basis of the date a particular unit is
    transferred. The IRS may challenge this treatment, which could
    change the allocation of items of income, gain, loss and
    deduction among our unitholders.
   21




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A
    unitholder whose units are loaned to a short seller
    to cover a short sale of units may be considered as having
    disposed of those units. If so, he would no longer be treated
    for tax purposes as a partner with respect to those units during
    the period of the loan and may recognize gain or loss from the
    disposition.
    We
    will adopt certain valuation methodologies that may result in a
    shift of income, gain, loss and deduction between the general
    partner and the unitholders. The IRS may challenge this
    treatment, which could adversely affect the value of the common
    units.
      The
    sale or exchange of 50% or more of our capital and profits
    interests during any twelve-month period will result in the
    termination of our partnership for federal income tax
    purposes.
    As a
    result of investing in our common units, you may become subject
    to state and local taxes and return filing requirements in
    jurisdictions where we operate or own or acquire
    property.
   22




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##### Table of Contents



Item 1B.
    Unresolved
    Staff Comments    Item 2.
    Properties  Major
    Coal Properties
    Northern
    Appalachia
  AFG-Southwest PA.
  Beaver Creek.
  Kingwood.
  Gatling.
   23




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Central
    Appalachia
  VICC/Alpha.
  D.D. Shepard.
 24




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Lynch.
  Dingess-Rum.
  VICC/Kentucky Land.
  Lone Mountain.
  Pardee.
   25




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26




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Southern
    Appalachia
  BLC Properties.
  Oak Grove.
    
 27




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Illinois
    Basin
  Hocking-Wolford/Cummings.
  Sato.
  Williamson Development.
    
  Northern
    Powder River Basin
  Western Energy. four-unit
 29




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Title to
    Property
     30




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Item 3.
    Legal
    Proceedings    Item 4.
    Submission
    of Matters to a Vote of Security Holders   31




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##### Table of Contents



PART II Item 5.
    Market
    for Registrants Common Units, Related Unitholder Matters
    and Issuer Purchases of Equity Securities    two-for-one
  Cash Distribution HistoryPrice Range


Per


Record


PaymentHigh


Low


Unit


Date


Date2006First Quarter

$
28.58


$
25.25


$
0.3950



05/01/2006



05/12/2006Second Quarter

$
29.48


$
25.60


$
0.4100



08/01/2006



08/14/2006Third Quarter

$
29.60


$
24.10


$
0.4250



11/01/2006



11/14/2006Fourth Quarter

$
29.99


$
24.75


$
0.4400



02/01/2007



02/14/20072007First Quarter

$
33.89


$
28.18


$
0.4550



05/01/2007



05/14/2007Second Quarter

$
38.94


$
31.60


$
0.4650



08/01/2007



08/14/2007Third Quarter

$
43.00


$
26.38


$
0.4750



11/01/2007



11/14/2007Fourth Quarter

$
35.61


$
29.71


$
0.4850



02/01/2008



02/14/2008        32




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Percentage
    Allocations of Available Cash from Operating Surplus
  Total Quarterly

Marginal Percentage Interest inDistribution Target

Distributions PaidAmount

Unitholders


General Partner


Holders of IDRsMinimum Quarterly Distribution

$0.25625


98
%


2
%


First Target Distribution

$0.25625 up to $0.28125


98
%


2
%


Second Target Distribution

above $0.28125 up to $0.33125


85
%


2
%


13
%Third Target Distribution

above $0.33125 up to $0.38125


75
%


2
%


23
%Thereafter

above $0.38125


50
%


2
%


48
%   Distributions
    of Cash to Partners
  OtherGeneral


Limited


Holders of


TotalPartner


Partners


IDRs


Distributions(In thousands)2005Distributions

$
1,504


$
70,952


$



$
72,456IDR Distributions


1,765







952



2,717Total Distributions


3,269



70,952



952



75,1732006Distributions


1,847



81,660







83,507IDR Distributions


5,756







3,099



8,855Total Distributions


7,603



81,660



3,099



92,3622007Distributions


2,939



118,858







121,797IDR Distributions


16,404







8,832



25,236Total Distributions

$
19,343


$
118,858


$
8,832


$
147,033    33




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##### Table of Contents



Item 6.
    Selected
    Financial Data    NATURAL
    RESOURCE PARTNERS L.P.
  For the Years Ended December 31,2007


2006


2005


2004


2003(In thousands, except per unit and per ton data)Income Statement Data:Revenues:Coal royalties

$
171,343


$
147,752


$
142,137


$
106,456


$
73,770Aggregate royalties


7,434



538











Coal processing fees


4,824



1,452











Transportation fees


3,984















Oil and gas royalties


4,930



4,220



3,180



1,907



1,675Property taxes


10,285



5,971



6,516



5,349



5,069Minimums recognized as revenue


1,951



2,082



1,709



1,763



2,033Override royalties


3,794



957



2,144



3,222



1,022Other


6,440



7,701



3,367



2,735



1,897Total revenues


214,985



170,673



159,053



121,432



85,466Expenses:Depreciation, depletion and amortization


51,391



29,695



33,730



30,077



24,483General and administrative


20,048



15,520



12,319



11,503



8,923Property, franchise and other taxes


13,613



8,122



8,142



6,835



5,810Transportation costs


298















Coal royalty and override payments


1,336



1,560



3,392



2,045



1,299Total expenses


86,686



54,897



57,583



50,460



40,515Income from operations


128,299



115,776



101,470



70,972



44,951Interest expense


(28,690
)


(16,423
)


(11,044
)


(11,192
)


(7,696
)Interest income


2,890



2,737



1,413



349



206Loss from early extinguishment of debt














(1,135
)


Loss on sale of assets


















(55
)Loss from interest rate hedge


















(499
)Net income

$
102,499


$
102,090


$
91,839


$
58,994


$
36,907Balance Sheet Data (at period end):Total assets

$
1,320,031


$
939,493


$
684,996


$
599,926


$
531,676Deferred revenue


36,286



20,654



14,851



15,847



15,054Long-term debt


496,057



454,291



221,950



156,300



192,650Total liabilities


575,440



503,806



259,088



190,734



223,518Partners capital


744,591



435,687



425,908



409,192



308,158Cash Flow Data:Net cash flow provided by (used in):Operating activities

$
168,153


$
138,843


$
121,675


$
90,847


$
64,528Investing activities


(79,634
)


(257,714
)


(105,702
)


(77,733
)


(142,511
)Financing activities


(96,222
)


137,224



(10,385
)


4,669



94,550Other Data:Royalty coal tons produced by lessees


57,232



52,092



53,606



48,357



44,344Average gross coal royalty revenue per ton

$
2.99


$
2.84


$
2.65


$
2.20


$
1.66Aggregate tons produced by lessee


5,698



412











Average gross aggregate royalty revenue per ton

$
1.30


$
1.31











Basic and diluted net income per limited partner unit

$
1.26


$
1.74


$
1.70


$
1.15


$
0.80Weighted average number of units outstanding:Common


54,582



34,366



28,690



26,894



22,708Subordinated


9,923



16,316



21,992



22,708



22,708Distributions per limited partner unit

$
1.880


$
1.670


$
1.450


$
1.238


$
1.075  34




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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 Consolidated Financial
    Statements.
  Executive
    Overview
  Our
    Business
          Current
    Results
       35




---



##### Table of Contents



Distributable
    Cash Flow
      Reconciliation
    of GAAP Net cash provided by operating activities
    to Non-GAAP Distributable cash flow
  For the Years Ended December 31,2007


2006


2005Net cash provided by operating activities

$
168,153


$
138,843


$
121,675Less scheduled principal payments


(9,350
)


(9,350
)


(9,350
)Less reserves for principal payments


(13,388
)


(9,600
)


(9,400
)Add reserves used for scheduled principal payments


9,400



9,400



9,400Distributable cash flow

$
154,815


$
129,293


$
112,325   Acquisitions
  Recent
    Acquisitions
   36




---



##### Table of Contents



2007
    Acquisitions
  Massey Energy.
  National Resources.
  Cheyenne Resources.
  Mid-Vol Coal Preparation Plant.
  Mettiki.
  Westmoreland.
  Dingess-Rum.
  Cline.
  2006
    Acquisitions
  Quadrant.
  Bluestone.
 37




---



##### Table of Contents



D.D. Shepherd.
  Red Fox.
  Coal Mountain.
  Williamson Development.
  Allegany County, Maryland.
  Indiana Reserves.
  Dispositions
  Virginia Land Sale.
  Virginia Timber Properties.
  Critical
    Accounting Policies
  Coal and Aggregate Royalties.
  Coal Processing and Transportation Fees.
  Oil and Gas Royalties.
 38




---



##### Table of Contents



Minimum Royalties.
  Depreciation and Depletion. units-of-production
  Impact of
    Adoption of FAS 123R
  Share-Based Payment,
  New
    Accounting Standard
  The
    Fair Value Option for Financial Assets and Financial
    Liabilities  Including an amendment of FASB Statement
    No. 115
 39




---



##### Table of Contents



Results
    of Operations
  Summary
    of 2007 and 2006 Royalties and Production
  For the Years EndedDecember 31,


Increase


Percentage2007


2006


(Decrease)


Change(In thousands, except percent and per ton data)Coal royaltiesAppalachiaNorthern

$
16,664


$
10,231


$
6,433



63
%Central


117,820



100,487



17,333



17
%Southern


17,832



20,469



(2,637
)


(13
)%Total Appalachia


152,316



131,187



21,129



16
%Illinois Basin


7,963



5,325



2,638



50
%Northern Powder River Basin


11,064



11,240



(176
)


(2
)%Total

$
171,343


$
147,752


$
23,591



16
%Production (tons)AppalachiaNorthern


7,270



5,329



1,941



36
%Central


35,835



31,991



3,844



12
%Southern


4,603



5,347



(744
)


(14
)%Total Appalachia


47,708



42,667



5,041



12
%Illinois Basin


3,709



2,877



832



29
%Northern Powder River Basin


5,815



6,548



(733
)


(11
)%Total


57,232



52,092



5,140



10
%Average gross royalty revenue per tonAppalachiaNorthern

$
2.29


$
1.92


$
0.37



19
%Central


3.29



3.14



0.15



5
%Southern


3.87



3.83



0.04



1
%Total Appalachia


3.19



3.07



0.12



4
%Illinois Basin


2.15



1.85



0.30



16
%Northern Powder River Basin


1.90



1.72



0.18



10
%Combined average gross royalty revenue per ton


2.99



2.84



0.15



5
%AggregatesRoyalty revenues

$
7,434


$
538


$
6,896



1282
%Production


5,698



412



5,286



1283
%Average gross royalty revenue per ton

$
1.30


$
1.31


$
(0.01
)


(1
%)   Coal Royalty Revenues and Production.
  Appalachia.
 40




---



##### Table of Contents



Northern Appalachia.
  Central Appalachia.
  Southern Appalachia.
  Illinois Basin.
  Northern Powder River Basin.
  Aggregates Royalty Revenues, Reserves and
    Production.
 41




---



##### Table of Contents



Summary
    of 2006 and 2005 Royalties and Production
  For the Years EndedDecember 31,


Increase


Percentage2006


2005


(Decrease)


Change(In thousands, except percent and per ton data)Coal royaltiesAppalachiaNorthern

$
10,231


$
11,306


$
(1,075
)


(10
)%Central


100,487



93,008



7,479



8
%Southern


20,469



25,089



(4,620
)


(18
)%Total Appalachia


131,187



129,403



1,784



1
%Illinois Basin


5,325



4,288



1,037



24
%Northern Powder River Basin


11,240



8,446



2,794



33
%Total

$
147,752


$
142,137


$
5,615



4
%Production (tons)AppalachiaNorthern


5,329



5,977



(648
)


(11
)%Central


31,991



32,790



(799
)


(2
)%Southern


5,347



6,263



(916
)


(15
)%Total Appalachia


42,667



45,030



(2,363
)


(5
)%Illinois Basin


2,877



2,781



96



3
%Northern Powder River Basin


6,548



5,795



753



13
%Total


52,092



53,606



(1,514
)


(3
)%Average gross royalty revenue per tonAppalachiaNorthern

$
1.92


$
1.89


$
.03



2
%Central


3.14



2.84



.30



11
%Southern


3.83



4.01



(.18
)


(4
)%Total Appalachia


3.07



2.87



.20



7
%Illinois Basin


1.85



1.54



.31



20
%Northern Powder River Basin


1.72



1.46



.26



18
%Combined average gross royalty revenue per ton


2.84



2.65



.19



7
%AggregatesRoyalty revenues

$
538






$
538



N/AProduction


412







412



N/AAverage gross royalty revenue per ton

$
1.31






$
1.31



N/A   Coal Royalty Revenues and Production.
  Appalachia.
  Northern Appalachia.
 42




---



##### Table of Contents



Central Appalachia.
  Southern Appalachia.
  Illinois Basin.
  Northern Powder River Basin.
  Other
    Operating Results
  Coal Transportation and Processing
    Revenues.
    Oil and Gas Royalties.
  Other revenues.
  Operating costs and expenses.
  
    Depletion and amortization of $51.4 million,
    $29.7 million and $33.7 million for the years ended
    December 31, 2007, 2006 and 2005, respectively.
    Fluctuations in depletion are dependent on the 43




---



##### Table of Contents



depletion rates where coal is mined, which can cause total
    depletion to be lower in periods where production is actually
    up. The new properties that we acquired in 2007 and at the end
    of 2006 are being depleted at much higher rates than our older
    properties, resulting in the significant increase in 2007.  
    General and administrative expenses of $20.0 million,
    $15.5 million and $12.3 million for the years ended
    December 31, 2007, 2006 and 2005, respectively. The
    increase in general and administrative expenses is primarily
    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 in 2006 as well as the steady increase in our unit
    price.
    Property, franchise and other taxes of $13.6 million,
    $8.1 million and $8.1 million for the years ended
    December 31, 2007, 2006 and 2005, respectively. The
    significant increase in 2007 was primarily due to taxes on
    additional properties we have acquired. A substantial portion of
    our property taxes is reimbursed to us by our lessees and is
    reflected as property tax revenue on our statement of income.  Interest Expense.
  Related
    Party Transactions
  Partnership
    Agreement
    The
    Cline Group
    Second Contribution Agreement.
 44




---



##### Table of Contents



Restricted Business Contribution Agreement.
  Investor Rights Agreement.
  Quintana
    Energy Partners, L.P.
  Form 10-K.
  5-person
    Liquidity
    and Capital Resources
  Cash
    Flows and Capital Expenditures
   45




---



##### Table of Contents



Contractual
    Obligations and Commercial Commitments
  Long-Term
    Debt
    
    $48.0 million of our $300 million floating rate
    revolving credit facility, due March 2012;
    $35.0 million of 5.55% senior notes due 2013;
    $55.8 million of 4.91% senior notes due 2018;
    $100.0 million of 5.05% senior notes due 2020;
    $2.7 million of 5.31% utility local improvement obligation
    due 2021;
    $46.8 million of 5.55% senior notes due 2023; and
    $225.0 million of 5.82% senior notes due 2024.    Credit Facility.
 46




---



##### Table of Contents




    the higher of the federal funds rate plus an applicable margin
    ranging from 0% to 0.50% or the prime rate as announced by the
    agent bank; or
    at a rate equal to LIBOR plus an applicable margin ranging from
    0.45% to 1.50%.      
    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


2008


2009


2010


2011


2012


ThereafterLong-term debt (including current maturities)

$
725.1


$
42.6


$
41.7


$
55.8


$
53.4


$
98.9


$
432.7     (1)
    
    The amounts indicated in the table include principal and
    interest due on our senior notes, as well as the utility local
    improvement obligation related to our property in DuPont,
    Washington. The table also includes the $48.0 million
    outstanding principal balance at December 31, 2007 under
    our credit facility, which matures in March 2012.  Two-for-One
    Limited Partner Unit Split
  two-for-one
  Conversion
    of Class B Units
  two-for-one one-for-one
 47




---



##### Table of Contents



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




---



##### Table of Contents



Interest
    Rate Risk
   49




---



##### 



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


51Balance sheets as of December 31, 2007, and
    2006


52Income statements for the years ended
    December 31, 2007, 2006, and 2005


53Statements of partners capital for the
    years ended December 31, 2007, 2006, and 2005


54Statements of cash flows for the years ended
    December 31, 2007, 2006, and 2005


55Notes to financial statements


56   50




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
    CONSOLDATED FINANCIAL STATEMENTS
 REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM                  51




---



##### Table of Contents



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


December 31,2007


2006(In thousands, except forunit information)ASSETSCurrent assets:Cash and cash equivalents

$
58,341


$
66,044Restricted cash


6,240



Accounts receivable, net of allowance for doubtful accounts


27,643



23,357Accounts receivable  affiliate


1,005



21Other


1,009



1,411Total current assets


94,238



90,833Land


24,343



17,781Plant and equipment, net


61,441



29,615Coal and other mineral rights, net


1,030,088



798,135Intangible assets


106,222



Loan financing costs, net


3,098



2,197Other assets, net


601



932Total assets

$
1,320,031


$
939,493LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accounts payable and accrued liabilities

$
2,567


$
1,041Accounts payable  affiliate


104



105Current portion of long-term debt


17,234



9,542Accrued incentive plan expenses  current portion


3,993



5,418Property, franchise and other taxes payable


6,415



4,330Accrued interest


6,276



3,846Total current liabilities


36,589



24,282Deferred revenue


36,286



20,654Asset retirement obligation


39



Accrued incentive plan expenses


6,469



4,579Long-term debt


496,057



454,291Partners capital:Common units (outstanding: 64,891,136 in 2007, 39,327,430 in
    2006)


731,113



338,912Subordinated units (outstanding: 11,353,634 in 2006)






83,772General partners interest


14,177



12,138Holders of incentive distribution rights






1,616Accumulated other comprehensive loss


(699
)


(751
)Total partners capital


744,591



435,687Total liabilities and partners capital

$
1,320,031


$
939,493    52




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
 CONSOLIDATED
    STATEMENTS OF INCOME  For the Years Ended December 31,2007


2006


2005(In thousands, except per unit data)Revenues:Coal royalties

$
171,343


$
147,752


$
142,137Aggregate royalties


7,434



538



Coal processing fees


4,824



1,452



Transportation fees


3,984







Oil and gas royalties


4,930



4,220



3,180Property taxes


10,285



5,971



6,516Minimums recognized as revenue


1,951



2,082



1,709Override royalties


3,794



957



2,144Other


6,440



7,701



3,367Total revenues


214,985



170,673



159,053Operating costs and expenses:Depreciation, depletion and amortization


51,391



29,695



33,730General and administrative


20,048



15,520



12,319Property, franchise and other taxes


13,613



8,122



8,142Transportation costs


298







Coal royalty and override payments


1,336



1,560



3,392Total operating costs and expenses


86,686



54,897



57,583Income from operations


128,299



115,776



101,470Other income (expense)Interest expense


(28,690
)


(16,423
)


(11,044
)Interest income


2,890



2,737



1,413Net income

$
102,499


$
102,090


$
91,839Net income attributable to:General partner

$
14,315


$
9,717


$
4,491Holders of incentive distribution rights

$
7,216


$
4,133


$
1,429Limited partners

$
80,968


$
88,240


$
85,919Basic and diluted net income per limited partner unit:Common

$
1.26


$
1.74


$
1.70Subordinated

$
1.26


$
1.74


$
1.70Weighted average number of units outstanding:Common


54,582



34,366



28,690Subordinated


9,923



16,316



21,992    53




---



##### 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, 2004


27,973,812


$
243,814



22,707,316


$
157,324


$
8,802


$
105


$
(853
)

$
409,192Subordinated units converted to common


5,676,860



39,873



(5,676,860
)


(39,873
)














Redemption of fractional units upon conversion of subordinated
    units


(58
)


(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


33,650,614


$
292,990



17,030,456


$
123,114


$
10,024


$
582


$
(802
)

$
425,908Subordinated units converted to common


5,676,822



40,775



(5,676,822
)


(40,775
)














Redemption of fractional units upon conversion of subordinated
    units


(6
)


























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


39,327,430


$
338,912



11,353,634


$
83,772


$
12,138


$
1,616


$
(751
)

$
435,687Issuance of units for acquisitions


14,210,072



346,319











4,422











350,741Subordinated units converted to common


11,353,634



75,444



(11,353,634
)


(75,444
)














Capital contribution


















2,645











2,645Distributions to unitholders






(98,023
)






(20,835
)


(19,343
)


(8,832
)






(147,033
)Net income for the year ended December 31, 2007






68,461







12,507



14,315



7,216







102,499Loss on interest hedge


























52



52Comprehensive income


























52



102,551Balance at December 31, 2007


64,891,136


$
731,113










$
14,177






$
(699
)

$
744,591      54




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
 CONSOLIDATED
    STATEMENTS OF CASH FLOWS  For the Years Ended December 31,2007


2006


2005(In thousands)Cash flows from operating activities:Net income

$
102,499


$
102,090


$
91,839Adjustments to reconcile net income to net cash provided by
    operating activities:Depreciation, depletion and amortization


51,391



29,695



33,730Non-cash interest charge


443



349



318Gain on sale of assets


(1,236
)


(3,471
)


Change in operating assets and liabilities:Accounts receivable


(5,270
)


(1,426
)


(6,869
)Other assets


178



(579
)


(47
)Accounts payable and accrued liabilities


(464
)


381



84Accrued interest


2,430



2,312



1,268Deferred revenue


15,632



5,803



(996
)Accrued incentive plan expenses


465



3,497



1,670Property, franchise and other taxes payable


2,085



192



678Net cash provided by operating activities


168,153



138,843



121,675Cash flows from investing activities:Acquisition of land, coal and other mineral rights


(58,124
)


(240,517
)


(99,683
)Acquisition of plant and equipment


(16,695
)


(24,248
)


(6,019
)Proceeds from sale of assets


1,425



7,051



Cash placed in restricted account


(6,240
)






Net cash used in investing activities


(79,634
)


(257,714
)


(105,702
)Cash flows from financing activities:Proceeds from loans


285,400



254,000



125,000Deferred financing costs


(1,292
)


(64
)


(861
)Repayments of loans


(235,942
)


(24,350
)


(59,350
)Distributions to partners


(147,033
)


(92,362
)


(75,173
)Contributions by general partner


2,645







Fractional units redeemed upon conversion of subordinated units










(1
)Net cash (used in) provided by financing activities


(96,222
)


137,224



(10,385
)Net increase (decrease) in cash and cash equivalents


(7,703
)


18,353



5,588Cash and cash equivalents at beginning of period


66,044



47,691



42,103Cash and cash equivalents at end of period

$
58,341


$
66,044


$
47,691Supplemental cash flow information:Cash paid during the period for interest

$
25,771


$
13,734


$
9,459Non-cash financing activities:Equity issued for business combinations

$
330,064


$



$
Assets contributed by general partner in business combination


4,422







Liability assumed in business combination


1,989







Equity issued for assets purchased


16,255







Utility improvement obligation acquired






2,883



    55




---



##### 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
    Business
    Combinations
   56




---



##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Use of
    Estimates
    Cash
    Equivalents and Restricted Cash
    Accounts
    Receivable
    Land,
    Coal and Mineral Rights
    Plant
    and Equipment
    Asset
    Impairment
    Concentration
    of Credit Risk
   57




---



##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Fair
    Value of Financial Instruments
      Deferred
    Financing Costs
    Revenues
  Coal and Aggregate Royalties.
  Coal Processing and Transportation Fees.
  Oil and Gas Royalties.
  Minimum Royalties.
  Property
    Taxes
   58




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Income
    Taxes
    Share-Based
    Payment
  Share-Based Payment,
  New
    Accounting Standard
  The
    Fair Value Option for Financial Assets and Financial
    Liabilities  Including an amendment of FASB Statement
    No. 115
  3.
    Acquisitions
    and Business Combinations   59




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
      Dingess-Rum


Cline(In thousands)Land, plant and equipment

$
7,935


$
17,783Coal and other mineral rights


105,573



98,866Other assets






72Intangible assets






107,557Equity consideration


113,396



216,668Assets contributed by General Partner






4,422Transaction costs and liabilities assumed


112



3,188   4.
    Allowance
    for Doubtful Accounts    2007


2006


2005(In thousands)Balance, January 1

$
906


$
85


$
185Provision charged to operations:Accounts charged off


871



822



30Recovery of prior charge offs


(505
)


(1
)


(130
)Balance, December 31

$
1,272


$
906


$
85   5.
    Plant and
    Equipment    December 31,


December 31,2007


2006(In thousands)Plant construction in process

$
11,238


$
Plant and equipment at cost


54,758



30,266Less accumulated depreciation


(4,555
)


(651
)Net book value

$
61,441


$
29,615   For the Years Ended December 31,2007


2006


2005(In thousands)Total depreciation expense on plant and equipment

$
3,904


$
556


$
95  60




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  6.
    Coal and
    Other Mineral Rights    December 31,


December 31,2007


2006(In thousands)Coal and other mineral rights

$
1,247,814


$
970,342Less accumulated depletion and amortization


(217,726
)


(172,207
)Net book value

$
1,030,088


$
798,135   For the Years EndedDecember 31,2007

2006

2005(In thousands)Total depletion and amortization expense on coal and other
    mineral interests

$
45,519


$
28,487


$
32,667   7.
    Intangible
    Assets    As of December 31, 2007GrossCarrying


AccumulatedAmount


Amortization(In thousands)Finite-lived intangible assetsAbove market transportation contracts

$
82,276


$
1,045Above market coal leases


25,281



290$
107,557


$
1,335     Estimated amortization expense (In thousands)For year ended December 31, 2008


4,642For year ended December 31, 2009


4,810For year ended December 31, 2010


5,862For year ended December 31, 2011


5,862For year ended December 31, 2012


5,862  61




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  8.
    Two-For-One
    Limited Partner Unit Split    9.
    Long-Term
    Debt    December 31,


December 31,2007


2006(In thousands)$300 million floating rate revolving credit facility, due
    March 2012

$
48,000


$
214,0005.55% senior notes, with semi-annual interest payments in
    June and December, maturing June 2013


35,000



35,0004.91% senior notes, with semi-annual interest payments in
    June and December, with annual principal payments in June,
    maturing in June 2018


55,800



61,8505.05% senior notes, with semi-annual interest payments in
    January and July, with scheduled principal payments beginning
    July 2008, maturing in July 2020


100,000



100,0005.31% utility local improvement obligation, with annual
    principal and interest payments, maturing in March 2021


2,691



2,8835.55% senior notes, with semi-annual interest payments in
    June and December, with annual principal payments in June,
    maturing in June 2023


46,800



50,1005.82% senior notes, with semi-annual interest payments in
    March and September, with scheduled principal payments beginning
    March 2010, maturing in March 2024


225,000



Total debt


513,291



463,833Less  current portion of long term debt


(17,234
)


(9,542
)Long-term debt

$
496,057


$
454,291     2008

$
17,2342009


17,2342010


32,2342011


31,5172012


78,801Thereafter


336,271$
513,291    62




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
          10.
    Net
    Income Per Unit Attributable to Limited Partners    11.
    Related
    Party Transactions  Reimbursements
    to Affiliates of our General Partner
      Transactions
    with Cline Affiliates
     63




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Quintana
    Energy Partners, L.P.
    5-person
    12.
    Commitments
    and Contingencies  Legal
    Environmental
    Compliance
   64




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  13.
    Major
    Lessees    For the Years Ended December 31,2007


2006


2005Revenues


Percent


Revenues


Percent


Revenues


Percent(Dollars in thousands)Lessee A

$
15,708



7.3
%

$
15,527



9.0
%

$
18,220



11.5
%Lessee B

$
21,025



9.8
%

$
23,146



13.5
%

$
19,966



12.6
%Lessee C

$
7,161



3.3
%

$
12,883



7.5
%

$
17,056



10.7
%   14.
    Incentive
    Plans        Outstanding grants at the beginning of the period


515,220Grants during the period


174,002Grants vested and paid during the period


(181,356
)Forfeitures during the period


(400
)Outstanding grants at the end of the period


507,466    65




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##### Table of Contents



NATURAL
    RESOURCE PARTNERS L.P.
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    15.
    Subsequent
    Events (Unaudited)  Distributions
    Incentive
    Plans
    16.
    Supplemental
    Financial Data (Unaudited)  Selected
    Quarterly Financial Information
    (In thousands, except per unit data)
  First


Second


Third


Fourth2007

Quarter


Quarter


Quarter


QuarterTotal revenues

$
50,207


$
51,097


$
56,366


$
57,315Income from operations


28,391



29,078



35,316



35,514Net income

$
21,881


$
22,631


$
28,928


$
29,059Basic and diluted net income per limited partner unit

$
0.28


$
0.28


$
0.35


$
0.35Weighted average number of units outstanding:Common


50,893



52,925



53,537



59,214Subordinated


11,354



11,354



11,354



5,677Class B


1,048



607







   First








Fourth2006

Quarter


Second Quarter


Third Quarter


QuarterTotal 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

$
0.51


$
0.43


$
0.42


$
0.38Weighted average number of units outstanding:Common


33,650



33,650



33,650



36,490Subordinated


17,030



17,030



17,030



14,192   66




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##### Table of Contents



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

$
0.38


$
0.46


$
0.40


$
0.46Weighted average number of units outstanding:Common


27,974



27,974



22,974



30,814Subordinated


22,708



22,708



22,708



19,868  67




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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).
  Form 10-K,
  Report of
    Independent Registered Public Accounting Firm
         68




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##### Table of Contents



Item 9B.
    Other
    Information  None.
 69




---



##### Table of Contents



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

Age

Position with the General PartnerCorbin J. Robertson, Jr.


60


Chairman of the Board and Chief Executive OfficerNick Carter


61


President and Chief Operating OfficerDwight L. Dunlap


54


Chief Financial Officer and TreasurerKevin F. Wall


51


Vice President and Chief EngineerKathy H. Roberts


56


Vice President Investor RelationsWyatt L. Hogan


36


Vice President, General Counsel and SecretaryKevin J. Craig


39


Vice President, Business DevelopmentKenneth Hudson


53


ControllerRobert T. Blakely


66


DirectorDavid M. Carmichael


69


DirectorJ. Matthew Fifield


34


DirectorRobert B. Karn III


66


DirectorS. Reed Morian


61


DirectorW. W. Scott, Jr.


62


DirectorStephen P. Smith


46


DirectorLeo A. Vecellio, Jr.


61


Director   Corbin J. Robertson, Jr.
  Nick Carter
  Dwight L. Dunlap
 70




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##### Table of Contents



Kevin F. Wall
  Kathy H. Roberts
  Wyatt L. Hogan
  Kevin J. Craig
  Kenneth Hudson
  Robert T. Blakely
 71




---



##### Table of Contents



David M. Carmichael
  J. Matthew Fifield
  Robert B. Karn III
  S. Reed Morian
  W. W. Scott, Jr.
  Stephen P. Smith
 72




---



##### Table of Contents



Leo A. Vecellio, Jr.
  Corporate
    Governance
  Board
    Attendance and Executive Sessions
    Independence
    of Directors
  Regulation S-K.
  Report
    of the Audit Committee
         73




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##### Table of Contents



Form 10-Q Form 10-K
  Form 10-K
  
  Compensation,
    Nominating and Governance 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;
    reviewing and recommending the annual and long-term incentive
    plans in which our executive officers participate; and
    reviewing and approving compensation for the board of directors.     74




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##### Table of Contents



Report
    of the Compensation, Nominating and Governance
    Committee
  Regulation S-K Form 10-K
  
  Section 16(a)
    Beneficial Ownership Reporting Compliance
    Partnership
    Agreement
  www.nrplp.com
  Corporate
    Governance Guidelines and Code of Business Conduct and
    Ethics
  Regulation S-K. www.nrplp.com
  NYSE
    Certification
    Item 11.
    Executive
    Compensation  Compensation
    Discussion and Analysis
  Overview
   75




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##### Table of Contents



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.      20-day Role of Compensation
    Experts
   76




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##### Table of Contents



Form 10-K.
  Role
    of Our Executive Officers in the Compensation
    Process
    Components
    of Compensation
  Base
    Salaries
    Annual
    Cash Incentive Awards
     77




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##### Table of Contents



Long-Term
    Incentive Compensation
      2003-2007,
  Perquisites
    and Other Personal Benefits
        Unit
    Ownership Requirements
    Securities
    Trading Policy
   78




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##### Table of Contents



Tax
    Implications of Executive Compensation
    Accounting
    Implications of Executive Compensation
  book-up
  Summary
    Compensation Table
    Change inPensionValue andNon-Equity

Non-QualifiedPhantom



Incentive

DeferredUnit

Option

Plan

Compensation

All OtherSalary

Bonus

Awards(1)

Awards

Compensation

Earnings

Compensation(2)

TotalName and Principal Position

Year

($)

($)

($)

($)

($)

($)

($)

($)Corbin J. Robertson, Jr.


2007











991,308















225,000



1,216,308Chairman and CEO


2006











899,387















74,857



974,244Dwight L. Dunlap


2007



219,417



100,000



326,689















181,662



827,768CFO and Treasurer


2006



176,908



100,000



298,926















86,164



661,998Nick Carter


2007



291,000



200,000



495,651















261,116



1,247,767President and COO


2006



261,900



200,000



449,683















110,973



1,022,556Wyatt L. Hogan


2007



221,563



60,000



283,356















175,591



740,510Vice President, General Counsel and Secretary


2006



174,018



60,000



183,384















79,632



497,034Kevin F. Wall


2007



133,380



75,000



245,922















173,869



628,171Vice 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
    2003-2007
    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 14 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. 79




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##### Table of Contents



Grants of
    Plan-Based Awards in 2007
  All OtherUnit Awards:


Grant Date FairNumber of


Value ofPhantom Units(1)


Unit Awards(2)Named Executive Officer

Grant Date


(#)


($)Corbin J. Robertson, Jr.


2/13/2007



26,000



900,760Dwight L. Dunlap


2/13/2007



7,200



249,441Nick Carter


2/13/2007



13,000



450,380Wyatt L. Hogan


2/13/2007



6,800



235,583Kevin F. Wall


2/13/2007



6,000



207,868     (1)
    
    The phantom units were granted in February 2007 and will vest in
    February 2011.(2)
    
    Amounts represent the estimated fair value on February 13,
    2007 using the Black-Scholes formula.  Form 10-K
        Outstanding
    Awards at December 31, 2007
    Number of


Market ValuePhantom Units That


of Phantom Units ThatHave Not Vested


Have Not Vested(1)Named Executive Officer

(#)


($)Corbin J. Robertson, Jr.


83,680



2,716,253Dwight L. Dunlap


27,440



890,702Nick Carter


41,840



1,358,126Wyatt L. Hogan


23,600



766,056Kevin F. Wall


20,880



677,765     (1)
    
    Based on a unit price of $32.46, the closing price for the
    common units on December 31, 2007. 80




---



##### Table of Contents



Phantom
    Units Vested in 2007
    Number ofPhantom Units That


Value RealizedVested


on VestingNamed Executive Officer

(#)


($)Corbin J. Robertson, Jr.


47,050



1,452,904Dwight L. Dunlap


14,674



453,133Nick Carter


23,524



726,421Wyatt L. Hogan


4,852



170,412Kevin F. Wall


10,792



333,257   Potential
    Payments upon Termination or Change in Control
  20-day
  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.


83,680







2,754,369Dwight L. Dunlap


27,440







903,201Nick Carter


41,840







1,377,185Wyatt L. Hogan


23,600







776,806Kevin F. Wall


20,880







687,276   Directors
    Compensation for the Year Ended December 31, 2007
    Fees Earnedor Paid in


PhantomCash


Unit Awards(1)(2)


TotalName

($)


($)


($)Robert Blakely


60,000



144,170



204,170David Carmichael


60,000



144,170



204,170J. Matthew Fifield


35,000



255,745



290,745Robert Karn III


60,000



144,170



204,170S. Reed Morian


35,000



144,170



179,170Stephen Smith


40,000



144,170



184,170W. W. Scott, Jr.


35,000



144,170



179,170Leo A. Vecellio, Jr.


23,333



230,785



254,118  81




---



##### Table of Contents



(1)
    
    Amounts represent the expense incurred by NRP for awards granted
    from
    2003-2007
    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. Because upon
    their appointments as directors in 2007, Mr. Fifield and
    Mr. Vecellio each received grants vesting over the next
    four years, the expense allocated to their awards was larger
    than the expense allocated to the other directors. For a
    description of the assumptions made in the FAS 123R
    calculation, please see Note 14 in Notes to Consolidated
    Financial Statements on page 61of this
    Form 10-K.(2)
    
    As of December 31, 2007, each director other than
    Mr. Vecellio held 12,000 phantom units that vest in annual
    increments of 3,000 units in each of 2008, 2009, 2010 and
    2011. Mr. Vecellio held 11,250 phantom units, of which
    2,250 units vest in 2008 and 3,000 units vest in each
    of 2009, 2010 and 2011.    2008
    Long-Term Incentive Awards
    Item 12.
    Security
    Ownership of Certain Beneficial Owners and
    Management   82




---



##### Table of Contents



Common


Percentage ofName of Beneficial Owner

Units


Common Units(1)Corbin J. Robertson, Jr.(2)


18,120,484



27.9
%Western Pocahontas Properties(3)(4)


17,279,860



26.6
%Adena Minerals LLC(5)


8,910,072



13.7
%Dingess-Rum Properties, Inc.(6)


4,800,000



7.4
%Neuberger Berman Inc.(7)


4,177,752



6.4
%Great Northern Properties(4)


2,979,558



4.6
%Nick Carter(8)


12,210



*Dwight L. Dunlap


9,000



*Kevin F. Wall(9)


2,500



*Kathy H. Roberts


11,000



*Wyatt L. Hogan(10)


1,500



*Kenneth Hudson


2,000



*Kevin J. Craig


850



*Robert T. Blakely






David M. Carmichael


10,000



*J. Matthew Fifield






Robert B. Karn III


5,600



*S. Reed Morian


30,000



*W. W. Scott, Jr.


10,620



*Stephen P. Smith


3,552



*Leo A. Vecellio, Jr.


10,000



*Directors and Officers as a Group


18,229,316



28.1
%     *
    
    Less than one percent.(1)
    
    Percentages based upon 64,891,136 common units issued and
    outstanding. Unless otherwise noted, beneficial ownership is
    less than 1%.(2)
    
    Mr. Robertson may be deemed to beneficially own the
    17,279,860 common units owned by Western Pocahontas Properties
    Limited Partnership, and the 670,024 common units owned by New
    Gauley Coal Corporation. Also included are 139,060 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 31,540 common units held
    by Barbara Robertson, Mr. Robertsons spouse.
    Mr. Robertsons address is 601 Jefferson Street,
    Suite 3600, Houston, Texas 77002.(3)
    
    These units may be deemed to be beneficially owned by
    Mr. Robertson.(4)
    
    The address of Western Pocahontas Properties Limited Partnership
    and Great Northern Properties Limited Partnership is 601
    Jefferson Street, Suite 3600, Houston, Texas 77002.(5)
    
    The address of Adena Minerals LLC is 3801 PGA Boulevard,
    Suite 803, Palm Beach Gardens, FL 33410.(6)
    
    The address of Dingess-Rum Properties, Inc. is 405 Capital
    Street, Suite 701, Charleston, WV 25301.(7)
    
    Includes 3,698,468 common units over which Neuberger Berman has
    sole voting and shared dispositive power and 479,284 common
    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.(8)
    
    Includes 210 common units held by Mr. Carters spouse. 83




---



##### Table of Contents



(9)
    
    Includes 500 common units held by Mr. Walls daughter
    and 500 common units held by Mr. Walls son.
    Mr. Wall disclaims beneficial ownership of these securities.(10)
    
    Of these common units, 500 common units are owned by the Anna
    Margaret Hogan 2002 Trust, 500 common units are owned by the
    Alice Elizabeth Hogan 2002 Trust, and 500 common units are held
    by the Ellen Catlett Hogan 2005 Trust. Mr. Hogan is a
    trustee of each of these trusts.  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 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.Assuming we have sufficient available cash to pay the current
    quarterly distribution of $0.485 on all of our outstanding units
    for four quarters in 2008, our general partner would receive
    distributions of approximately $3.2 million on its 2% general
    partner interest and our affiliates would receive distributions
    of approximately $125.8 million on their common units.  In
    addition in 2008, our general partner and affiliates of our
    general partner would receive an aggregate of approximately
    $31.8 million with respect to their incentive distribution
    rights.Other payments to our general partner and its affiliates

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
   84




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##### Table of Contents




    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
    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.         85




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##### Table of Contents



The Cline
    Group
    Second Contribution Agreement.
 86




---



##### Table of Contents



Restricted Business Contribution
    Agreement.
  Investor Rights Agreement.
  Quintana
    Energy Partners, L.P.
    
    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 87




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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 for 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 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.  5-person
    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; 88




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
    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.    Actions
    taken by our general partner may affect the amount of cash
    available for distribution to unitholders.
    
    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.        We do
    not have any officers or employees and rely solely on officers
    and employees of GP Natural Resource Partners LLC and its
    affiliates.
   89




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##### Table of Contents



We
    reimburse our general partner and its affiliates for
    expenses.
    Our
    general partner intends to limit its liability regarding our
    obligations.
    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.
   90




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Director
    Independence
    Item 14.
    Principal
    Accounting Fees and Services    2007


2006Audit Fees(1)

$
415,241


$
385,725Audit-Related Fees






Tax Fees(2)

$
445,749


$
400,920All 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.(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
   91




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##### Table of Contents



pre-approval pre-approval, pre-approved
      II.
    Delegation    III.  Audit
    Services
      IV.
    Audit-related
    Services   92




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##### Table of Contents



agreed-upon and/or
  V.
    Tax
    Services    VI.
    Pre-Approval
    Fee Levels or Budgeted Amounts    VII.  Procedures
     93




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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).2
.4



Amendment No. 1 to Second Contribution Agreement, dated
    April 18, 2007, by and among Natural Resource Partners
    L.P., NRP (GP) LP, NRP (Operating) LLC, Foresight Reserves LP
    and Adena Minerals, LLC (incorporated by reference to
    Exhibit 2.1 to the Current Report on
    Form 8-K
    filed on April 19, 2007).2
.5



Purchase and Sale Agreement, dated April 2, 2007, by and
    among Natural Resource Partners L.P., WPP LLC and Western
    Pocahontas Properties Limited Partnership (incorporated by
    reference to Exhibit 2.1 to the Current Report on
    Form 8-K
    filed on April 3, 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



Third Amended and Restated Agreement of Limited Partnership of
    Natural Resource Partners L.P., dated April 18, 2007
    (incorporated by reference to Exhibit 4.1 of the Current
    Report on
    Form 8-K
    filed on April 19, 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). 94




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##### Table of Contents



ExhibitNumber



Description4
.7



Second Supplement to Note Purchase Agreements, dated as of
    March 28, 2007 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 March 29, 2007).4
.8



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
.9



Second Amendment, dated as of March 28, 2007, 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 March 29, 2007).4
.10



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
.11



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
.12



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
.13



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
.14



Form of Series D Note (incorporated by reference to
    Exhibit 4.12 to the Annual Report on
    Form 10-K
    filed February 28, 2007.4
.15



Form of Series E Note (incorporated by reference to
    Exhibit 4.3 to the Current Report on
    Form 8-K
    filed March 29, 2007).10
.1



Amended and Restated Credit Agreement, dated as of
    March 28, 2007, by and among NRP (Operating) LLC, as
    Borrower, Citibank, N.A., as Administrative Agent, and the other
    lenders party thereto (incorporated by reference to
    Exhibit 10.1 to the Current Report on
    Form 8-K
    filed on March 29, 2007).10
.2



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
.3



Natural Resource Partners Amended and Restated Long-Term
    Incentive Plan (incorporated by reference to Exhibit 10.1
    to the Current Report on
    Form 8-K
    filed on January 16, 2008).10
.4*



Form of Phantom Unit Agreement.10
.5



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
.6



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
.7



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). 95




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##### Table of Contents



ExhibitNumber



Description10
.8



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
.9



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
.10



Assignment, Waiver and Amendment Agreement, dated
    January 20, 2006, by and among Williamson Development
    Company, LLC, ACIN LLC and WPP LLC.10
.11



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).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-Oxley.31
.2*



Certification of Chief Financial Officer pursuant to
    Section 302 of Sarbanes-Oxley.32
.1**



Certification of Chief Executive Officer pursuant to
    18 U.S.C. § 1350.32
.2**



Certification of Chief Financial Officer pursuant to
    18 U.S.C. § 1350.99
.1*



Audited balance sheet of NRP (GP) LP     *
    
    Filed herewith**
    
    Furnished herewith 96




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##### Table of Contents



SIGNATURES
    NATURAL RESOURCE PARTNERS L.P.
    By: NRP (GP) LP, its general partner
    By:
    GP NATURAL RESOURCE
    PARTNERS LLC, its general partner  By:
    /s/  CORBIN
    J. ROBERTSON, JR.,         By:
    /s/  DWIGHT
    L. DUNLAP        By:
    /s/  KENNETH
    HUDSON        By:
    /s/  ROBERT
    T. BLAKELY       By:
    /s/  DAVID
    M. CARMICHAEL      97




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##### Table of Contents



J.
    MATTHEW FIFIELD
       By:
    /s/  ROBERT
    B. KARN III       By:
    /s/  S.
    REED MORIAN       By:
    /s/  W.W.
    SCOTT, JR.       By:
    /s/  STEPHEN
    P. SMITH       By:
    /s/  LEO
    A. VECELLIO      98