S-1/A 1 h95980a5sv1za.txt NATURAL RESOURCE PARTNERS L.P.-AMEND.#5 333-86582 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 10, 2002 REGISTRATION NO. 333-86582 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------- AMENDMENT NO. 5 TO FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 --------------------- NATURAL RESOURCE PARTNERS L.P. (Exact Name of Registrant as Specified in Its Charter) --------------------- DELAWARE 1222 35-2164875 (State or Other Jurisdiction (Primary Standard Industrial (I.R.S. Employer of Incorporation or Classification Code Number) Identification Number) Organization) 601 JEFFERSON STREET, SUITE 3600 HOUSTON, TEXAS 77002 (713) 751-7507 (Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant's Principal Executive Offices) DWIGHT L. DUNLAP 601 JEFFERSON STREET, SUITE 3600 HOUSTON, TEXAS 77002 (713) 751-7507 (Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service) --------------------- COPIES TO: DAN A. FLECKMAN JOSHUA DAVIDSON VINSON & ELKINS L.L.P. BAKER BOTTS L.L.P. 1001 FANNIN, SUITE 2300 910 LOUISIANA HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002 (713) 758-2222 (713) 229-1234 --------------------- APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after this Registration Statement becomes effective. --------------------- If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] --------------------- THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. SUBJECT TO COMPLETION, DATED OCTOBER 10, 2002 PROSPECTUS (NATURAL RESOURCE PARTNERS L.P. LOGO) NATURAL RESOURCE PARTNERS L.P. 4,575,503 COMMON UNITS REPRESENTING LIMITED PARTNER INTERESTS $ PER COMMON UNIT --------------------- We are selling 2,598,750 common units and Arch Coal, Inc., as the selling unitholder, is selling 1,901,250 common units. We will not receive any proceeds from the sale of common units by Arch Coal, Inc. We and Arch Coal, Inc. have granted the underwriters a 30-day option to purchase up to an additional 675,000 common units on the same terms and conditions as set forth in this prospectus to cover over-allotments of common units, if any. To the extent the underwriters do not exercise this option in full, affiliates of our general partner will purchase up to an additional 75,503 common units at the initial public offering price, such that a minimum of 4,575,503 common units will be sold in the offering. We are a limited partnership recently formed by Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and Arch Coal, Inc. This is the initial public offering of our common units. We expect the initial public offering price to be between $19.00 and $21.00 per unit. We intend to make a minimum quarterly distribution of available cash of $0.5125 per unit, or $2.05 per unit on an annualized basis, before any distributions are paid on our subordinated units, to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. The common units have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol "NRP." --------------------- INVESTING IN THE COMMON UNITS INVOLVES RISK. PLEASE READ "RISK FACTORS" BEGINNING ON PAGE 14. These risks include the following: - 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. - A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves. - Our lessees' coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us. - 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. - We depend on a limited number of primary operators for a significant portion of our coal royalty revenues. - Due to our lack of asset diversification, adverse developments in the coal industry could reduce our coal royalty revenues. - A recent federal district court ruling could preclude our lessees from obtaining Clean Water Act permits required for some of their future operations and could also result in the revocation of existing permits. - The owners of our general partner and their affiliates may engage in substantial competition with us and have other conflicts of interest and limited fiduciary responsibilities that may permit them to favor their own interests to your detriment. - Even if unitholders are dissatisfied, they cannot easily remove our general partner. - The control of our general partner may be transferred to a third party without unitholder consent. - You will experience immediate and substantial dilution of $6.14 per common unit. - You may be required to pay taxes on income from us even if you do not receive any cash distributions from us. NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. ---------------------

PER COMMON UNIT TOTAL ---------- -------- Public Offering Price $ $ Underwriting Discount $ $ Proceeds to Natural Resource Partners L.P. before expenses $ $ Proceeds to Selling Unitholder $ $

The underwriters expect to deliver the common units on or about , 2002. SALOMON SMITH BARNEY LEHMAN BROTHERS CIBC WORLD MARKETS FRIEDMAN BILLINGS RAMSEY RBC CAPITAL MARKETS , 2002 TABLE OF CONTENTS SUMMARY..................................................... 1 Natural Resource Partners................................. 1 Partnership Structure and Management...................... 6 The Offering.............................................. 8 Summary Pro Forma Financial and Operating Data............ 11 Summary of Conflicts of Interest and Fiduciary Responsibilities....................................... 13 RISK FACTORS................................................ 14 Risks Related to Our Business............................. 14 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... 14 A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves......................................... 15 Our lessees' coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us................................ 15 We depend on a limited number of primary operators for a significant portion of our coal royalty revenues, and the loss of or reduction in production from any of our major operators could reduce our coal royalty revenues.............................................. 16 We may not be able to terminate our leases if any of our lessees declare bankruptcy, and we may experience delays and be unable to replace lessees that do not make royalty payments............................................. 16 If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease........................................ 16 Due to our lack of asset diversification, adverse developments in the coal industry could reduce our coal royalty revenues................................. 17 Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would thereby reduce our coal royalty revenues........ 17 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.................................. 17 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.............................................. 17 Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more, which could adversely affect the stability and profitability of their operations and adversely affect our coal royalty revenues...................... 18 Competition within the coal industry may adversely affect the ability of our lessees to sell coal, and excess production capacity in the industry could put downward pressure on coal prices...................... 18 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.............................. 19 Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties............................................ 19 Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves....... 19 Our lessees' work forces could become increasingly unionized in the future............................... 19 Regulatory and Legal Risks................................ 20 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............. 20 A substantial portion of our coal has a high sulfur content. This coal may become more difficult to sell because the Clean Air Act restricts the ability of electric utilities to burn high sulfur coal........... 21 A recent federal district court ruling could preclude our lessees from obtaining Clean Water Act permits required for some of their future operations and could also result in the revocation of existing permits..... 21 ii The Clean Air Act affects the end-users of coal and could significantly affect the demand for our coal and reduce our coal royalty revenues...................... 22 We may become liable under federal and state mining statutes if our lessees are unable to pay mining reclamation costs..................................... 23 A recent federal district court decision could limit our lessees' ability to conduct underground mining operations............................................ 23 Restructuring of the electric utility industry could lead to reduced coal prices........................... 24 We could become liable under federal and state Superfund and waste management statutes............... 24 Risks Related to Our Partnership Structure................ 24 The WPP Group and Arch Coal may engage in substantial competition with us................................... 24 The WPP Group, Arch Coal and their affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment....................... 26 Even if unitholders are dissatisfied, they cannot easily remove our general partner..................... 27 The control of our general partner may be transferred to a third party without unitholder consent........... 28 Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to unitholders........................................... 28 You will experience immediate and substantial dilution of $6.14 per common unit.............................. 28 We may issue additional common units without your approval, which would dilute your existing ownership interests............................................. 28 Cost reimbursements due our general partner may be substantial and will reduce the cash available for distribution to you................................... 29 Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.............................................. 29 Your liability may not be limited if a court finds that unitholder action constitutes control of our business.............................................. 29 Tax Risks to Common Unitholders........................... 30 The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to you..................... 30 A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will be borne by our unitholders and our general partner... 30 You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.................................................... 30 Tax gain or loss on disposition of common units could be different than expected............................ 31 Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.................................. 31 We will register as a tax shelter. This may increase the risk of an IRS audit of us or you................. 31 You will likely be subject to state and local taxes in states where you do not live as a result of an investment in units................................... 31 USE OF PROCEEDS............................................. 32 CAPITALIZATION.............................................. 33 DILUTION.................................................... 34 CASH DISTRIBUTION POLICY.................................... 35 Quarterly Distributions of Available Cash................. 35 Operating Surplus and Capital Surplus..................... 35 Subordination Period...................................... 36 Distributions of Available Cash From Operating Surplus During the Subordination Period........................ 38 Distributions of Available Cash from Operating Surplus After the Subordination Period......................... 38 Incentive Distribution Rights............................. 38 Percentage Allocations of Available Cash from Operating Surplus................................................ 39 Distributions From Capital Surplus........................ 39 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.................................... 40 Distributions of Cash Upon Liquidation.................... 40 CASH AVAILABLE FOR DISTRIBUTION............................. 43 iii SELECTED HISTORICAL FINANCIAL AND OPERATING DATA............ 46 Western Pocahontas Properties Limited Partnership......... 47 Great Northern Properties Limited Partnership............. 48 New Gauley Coal Corporation............................... 49 Arch Coal Contributed Properties.......................... 50 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................. 51 Introduction.............................................. 51 Results of Operations..................................... 52 Related Party Transactions................................ 60 Liquidity and Capital Resources........................... 60 Contractual Obligations and Commercial Commitments........ 62 Inflation................................................. 63 Environmental............................................. 64 Recent Accounting Pronouncements.......................... 64 Critical Accounting Policies.............................. 65 Quantitative and Qualitative Disclosures about Market Risk................................................... 66 COAL INDUSTRY OVERVIEW...................................... 67 Introduction.............................................. 67 Coal Markets.............................................. 67 Industry Trends........................................... 68 Coal Royalty Business..................................... 69 Largest U.S. Coal Producers............................... 70 Imports and Exports....................................... 70 Coal Characteristics...................................... 71 Coal Mining Techniques.................................... 72 Coal Preparation.......................................... 73 Coal Regions.............................................. 73 Coal Prices............................................... 74 BUSINESS.................................................... 77 Business Strategy......................................... 77 Competitive Strengths..................................... 78 Our Relationship with the WPP Group and Arch Coal......... 79 Coal Reserves and Production.............................. 79 Coal Leases............................................... 81 Central Appalachia (Eastern Kentucky and Virginia)........ 82 Central Appalachia (Southern West Virginia)............... 85 Northern Appalachia....................................... 88 Southern Appalachia....................................... 90 Illinois Basin............................................ 92 Northern Powder River Basin............................... 94 Other Operations.......................................... 96 Coal Industry Sales Contracts............................. 96 Competition............................................... 96 Regulation................................................ 97 Title to Property......................................... 106 Employees and Labor Relations............................. 107 Legal Proceedings......................................... 107 MANAGEMENT.................................................. 108 GP Natural Resource Partners LLC Will Manage Us........... 108 Directors and Executive Officers of GP Natural Resource Partners LLC........................................... 109 Reimbursement of Expenses of our General Partner.......... 110 Executive Compensation.................................... 110 Compensation of Directors................................. 111 Long-Term Incentive Plan.................................. 111 iv Annual Incentive Plan..................................... 112 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT................................................ 113 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 114 Distributions and Payments to the General Partner and its Affiliates............................................. 114 Agreements Governing the Transactions..................... 115 Omnibus Agreement......................................... 116 Agreements with Ark Land Company.......................... 118 CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES........ 120 Conflicts of Interest..................................... 120 Fiduciary Responsibilities................................ 122 SELLING UNITHOLDER.......................................... 125 DESCRIPTION OF THE COMMON UNITS............................. 126 The Units................................................. 126 Transfer Agent and Registrar.............................. 126 Transfer of Common Units.................................. 126 DESCRIPTION OF THE SUBORDINATED UNITS....................... 128 Conversion of Subordinated Units.......................... 128 Limited Voting Rights..................................... 129 Distributions Upon Liquidation............................ 129 THE PARTNERSHIP AGREEMENT................................... 130 Organization.............................................. 130 Purpose................................................... 130 Power of Attorney......................................... 130 Capital Contributions..................................... 131 Limited Liability......................................... 131 Voting Rights............................................. 132 Issuance of Additional Securities......................... 133 Amendment of the Partnership Agreement.................... 134 Actions Relating to Operating Company..................... 136 Merger, Sale or Other Disposition of Assets............... 136 Termination and Dissolution............................... 136 Liquidation and Distribution of Proceeds.................. 137 Withdrawal or Removal of the General Partner.............. 137 Transfer of General Partner Interest...................... 138 Transfer of Incentive Distribution Rights................. 139 Transfer of Ownership Interests in the General Partner.... 139 Change of Management Provisions........................... 139 Limited Call Right........................................ 139 Meetings; Voting.......................................... 140 Status as Limited Partner or Assignee..................... 141 Non-Citizen Assignees; Redemption......................... 141 Indemnification........................................... 141 Reimbursement of Expenses................................. 142 Books and Reports......................................... 142 Right to Inspect Our Books and Records.................... 142 Registration Rights....................................... 143 UNITS ELIGIBLE FOR FUTURE SALE.............................. 144 MATERIAL TAX CONSEQUENCES................................... 146 Partnership Status........................................ 146 Limited Partner Status.................................... 147 Tax Consequences of Unit Ownership........................ 148 v Tax Treatment of Operations............................... 152 Disposition of Common Units............................... 154 Tax-Exempt Organizations and Other Investors.............. 156 Administrative Matters.................................... 157 State, Local and Other Tax Considerations................. 159 INVESTMENT IN NATURAL RESOURCE PARTNERS BY EMPLOYEE BENEFIT PLANS..................................................... 160 UNDERWRITING................................................ 161 VALIDITY OF THE COMMON UNITS................................ 163 EXPERTS..................................................... 163 WHERE YOU CAN FIND MORE INFORMATION......................... 164 FORWARD-LOOKING STATEMENTS.................................. 165 INDEX TO FINANCIAL STATEMENTS............................... F-1 Appendix A -- First Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P. .... A-1 Appendix B -- Application for Transfer of Common Units...... B-1 Appendix C -- Glossary of Terms............................. C-1 Appendix D -- Estimated Available Cash From Operating Surplus................................................... D-1 Appendix E -- Coal Reserve Audit Summary Report of Weir International Mining Consultants.......................... E-1 Appendix F -- Coal Reserve Audit Summary Report of Stagg Resource Consultants, Inc................................. F-1 --------------------- You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date. Until , 2002 (25 days after the date of this prospectus), all dealers effecting transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions. vi SUMMARY This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the financial statements and the notes to those statements. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit, (2) that the underwriters' over-allotment option is not exercised and (3) that an additional 75,503 common units are purchased by New Gauley Coal Corporation and Great Northern Properties Limited Partnership. We present the reserve information for Natural Resource Partners in this prospectus on a pro forma basis as if the reserves had been contributed to us on December 31, 2001. You should read "Summary of Risk Factors" beginning on page 2 and "Risk Factors" beginning on page 14 for more information about important risks that you should consider before buying common units. In this prospectus, we refer to Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation collectively as the WPP Group. The estimates of Arch Coal, Inc.'s and the WPP Group's proven and probable reserves have been audited as of December 31, 2001 by Weir International Mining Consultants and Stagg Resource Consultants, Inc., respectively. Their Coal Reserve Audit Summary Reports have been included in this prospectus as Appendices E and F, respectively. Additionally, we have included a "Glossary of Terms" as Appendix C. NATURAL RESOURCE PARTNERS We are a limited partnership recently formed by the WPP Group, the largest owner of coal reserves in the United States other than the U.S. government, and Arch Coal, Inc., the second largest U.S. coal producer. We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2001, we controlled approximately 1.15 billion tons of proven and probable coal reserves in eight states. In 2001, our lessees produced 29 million tons of coal from our properties and our total revenues were $47.2 million on a pro forma basis, including coal royalty revenues of $42.4 million. We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. Our royalty payments are based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, subject to a minimum payment. As of September 1, 2002, our reserves were located on 45 separate properties and are subject to 62 leases with 31 lessees. In 2001, approximately 57% of the coal produced from our properties came from underground mines and 43% came from surface mines. As of December 31, 2001, approximately 65% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which meets the standards imposed by the Clean Air Act and constitutes approximately 25% of our reserves. Coal produced from our properties is burned in electric power plants located east of the Mississippi River and in Montana and Minnesota. Approximately 12% of our lessees' 2001 coal production was metallurgical coal, which our lessees sold to steel companies in the Eastern United States, South America, Europe and Asia. The table below shows coal production, coal royalty revenues and reserve tonnage for our properties as of December 31, 2001 on a pro forma basis. COAL ROYALTY REVENUES, PRODUCTION AND RESERVES BY REGION

YEAR ENDED AT DECEMBER 31, DECEMBER 31, 2001 2001 ------------------------- ----------------- COAL ROYALTY PROVEN AND REVENUES PRODUCTION PROBABLE RESERVES ------------ ---------- ----------------- (IN THOUSANDS) Appalachia..................................... $32,327 19,648 958,581 Illinois Basin................................. 3,155 2,659 28,398 Western United States.......................... 6,951 6,683 166,939 ------- ------ --------- Total..................................... $42,433 28,990 1,153,918 ======= ====== =========

1 DEMAND FOR COAL Over the last two decades, total domestic coal consumption in the United States has increased from approximately 733 million tons in 1981 to 1.1 billion tons in 2001. The growth in demand for coal has been primarily driven by growth in electricity consumption. In 2001, electric utilities accounted for approximately 90% of domestic coal consumption. We believe that demand for coal will continue to grow for the following reasons: - Demand for electricity will continue to increase as the economy grows. In order to meet the projected increase in demand for electricity, demand for coal by electricity generators is expected to increase by 1.2% per year between 2000 and 2020. We believe much of the projected increase in demand for electricity will be supplied by existing coal-fired power plants because they possess excess capacity that can be utilized at low incremental costs. - Coal prices have historically been lower and more stable than natural gas prices. The market price of natural gas has historically been more volatile and higher on an energy-equivalent basis than the market price of coal. While new natural gas-fired power plants generally are less expensive to construct than new coal-fired plants, we believe that higher prices and volatility will continue to make natural gas a less attractive energy source than coal for many utilities, particularly for baseload electricity generation. - There is an abundant supply of coal. Coal makes up approximately 95% of fossil fuel reserves in the United States, with an estimated 250-year supply of coal based on current usage rates. - Coal is increasingly less polluting. As a result of improved technology and coal consumption trends to lower sulfur coal, sulfur dioxide emissions from U.S. coal-fired power plants have declined by more than 20% since 1970, even as coal consumption for domestic electric power generation has almost tripled. - Demand for non-compliance coal production will continue. Although the Clean Air Act emission requirements have caused a general shift in demand toward lower sulfur coal, we believe that demand for our medium and high sulfur coal will continue because utilities currently may satisfy the Clean Air Act requirements by (1) burning lower sulfur coal mixed with medium or high sulfur coal, (2) installing pollution control devices, such as scrubbers, to reduce emissions from high sulfur coal or (3) purchasing or trading emission credits. SUMMARY OF RISK FACTORS An investment in our common units involves risks associated with our business, regulatory and legal matters, our partnership structure and the tax characteristics of our common units. Please carefully read the risks relating to these matters under "Risk Factors." RISKS RELATED TO OUR BUSINESS - 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. - A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves. - Our lessees' coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us. - We depend on a limited number of primary operators for a significant portion of our coal royalty revenues, and the loss of or reduction in production from any of our major operators could reduce our coal royalty revenues. 2 - We may not be able to terminate our leases if any of our lessees declare bankruptcy, and we may experience delays and be unable to replace lessees that do not make royalty payments. - If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease. - Due to our lack of asset diversification, adverse developments in the coal industry could reduce our coal royalty revenues. - Any decrease in demand for metallurgical coal could result in lower coal production by our lessees, which would thereby reduce our coal royalty revenues. REGULATORY AND LEGAL RISKS - 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. - A substantial portion of our coal has a high sulfur content. This coal may become more difficult to sell because the Clean Air Act restricts the ability of electric utilities to burn high sulfur coal. - A recent federal district court ruling could preclude our lessees from obtaining Clean Water Act permits required for some of their future operations and could also result in the revocation of existing permits. - The Clean Air Act affects the end-users of coal and could significantly affect the demand for our coal and reduce our coal royalty revenues. - We may become liable under federal and state mining statutes if our lessees are unable to pay mining reclamation costs. - A recent federal district court decision could limit our lessees' ability to conduct underground mining operations. RISKS RELATED TO OUR PARTNERSHIP STRUCTURE - The WPP Group and Arch Coal may engage in substantial competition with us. - The WPP Group, Arch Coal and their affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment. - Even if unitholders are dissatisfied, they cannot easily remove our general partner. - The control of our general partner may be transferred to a third party without unitholder consent. - Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to unitholders. - You will experience immediate and substantial dilution of $6.14 per common unit. TAX RISKS TO COMMON UNITHOLDERS - The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to you. - A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will be borne by our unitholders and our general partner. - You may be required to pay taxes on income from us even if you do not receive any cash distributions from us. - Tax gain or loss on disposition of common units could be different than expected. 3 BUSINESS STRATEGY We intend to execute the following strategies that we believe reflect our competitive strengths: - Maximize royalty revenues from our existing properties. We work with our lessees by providing technical knowledge of our reserves, including information about title and geology. We also review mine plans to assure efficient recovery of reserves and periodically audit our lessees to verify that royalties have been properly paid. - Explore new opportunities with our existing lessees. Our lessees are generally subsidiaries of large coal producers that have long-term plans to expand their operations. We intend to further develop our relationships with our current lessees in order to participate in future opportunities that our lessees may identify for acquiring or leasing new properties. - Add new lessees to diversify our coal mine operator base. We have identified additional public and private coal mine operators that meet our guidelines as qualified lessee candidates. As we expand our royalty business, we will be seeking new lessees to mine our properties. The addition of these new lessees will allow us to further diversify our coal mine operator base. - Expand and diversify our coal reserves. We intend to actively pursue opportunities to expand and diversify our reserves by acquiring additional coal properties that generate royalty income. We will review potential reserve acquisitions in all coal producing regions of the United States in order to acquire marketable reserves that we believe will be attractive to lessees. We expect to fund any acquisitions with borrowings under our credit facility and proceeds from the issuance of our common units. COMPETITIVE STRENGTHS We believe the following competitive strengths will enable us to execute our business strategies successfully: - Our royalty structure generates stable production and cash flow. Our leases provide for royalty rates generally equal to the higher of a percentage of the gross sales price or a fixed price per ton of coal, subject to a minimum payment. This structure generally allows our production and cash flow to be stable and predictable in periods of low coal prices, while enabling us to benefit during periods of higher coal prices. - We do not directly bear operating costs and risks. Because we do not operate any mines, we do not bear ordinary operating costs and have limited direct exposure to environmental compliance, permitting and labor risks, which are principally borne by our lessees, the operators of the mines. - We primarily lease to large lessees that have a diverse customer base. Our royalty income is primarily from leases to subsidiaries of publicly-held coal companies. In 2001, we derived approximately 76% of our revenues from subsidiaries of seven of the top ten coal producers in the United States. - Our reserves are diverse and strategically located. Our reserves are geographically diverse and cover a broad range of heat and sulfur content. By offering both metallurgical and steam coal, our coal reserves are marketable to a diverse customer base, thereby enabling our lessees to adjust to changing markets and sustain sales volumes and prices. - We are well-positioned to pursue acquisitions of coal reserves and other minerals. The coal royalty business is highly fragmented and characterized by numerous small entities that present potentially attractive acquisition opportunities. In conjunction with this offering, we are entering into a $100 million credit facility that, combined with our ability to issue additional units, should provide the financial flexibility to pursue acquisitions. Upon the closing of this offering, we anticipate that we will have no outstanding indebtedness. 4 - We have experienced, knowledgeable management. Our management team has a successful record of managing, leasing and acquiring properties. Each member of our management team has at least 20 years of experience in the mining industry. OUR RELATIONSHIP WITH THE WPP GROUP AND ARCH COAL The WPP Group and Arch Coal have a significant interest in our partnership through their combined ownership of a 78.6% limited partner interest and the 2% general partner interest in our partnership. Both the WPP Group and Arch Coal have a history of successfully completing and integrating acquisitions in the coal industry. We expect to pursue acquisitions with the WPP Group and Arch Coal, as well as with other companies. We may acquire coal reserve properties, other mineral properties or producing coal properties, in which event we would expect to work with a coal producing company that would acquire the mine assets and lease the reserves from us. While our relationship with both the WPP Group and Arch Coal should provide significant benefits to us, it is also a source of potential conflict. In addition, the WPP Group and Arch Coal may engage in substantial competition with us. Please read "Conflicts of Interest and Fiduciary Responsibilities" and "Certain Relationships and Related Transactions -- Omnibus Agreement." 5 PARTNERSHIP STRUCTURE AND MANAGEMENT Our operations will be conducted through, and our operating assets will be owned by, our subsidiaries. We will own our subsidiaries through an operating company, NRP (Operating) LLC. Upon consummation of the offering of the common units and the related transactions: - NRP (GP) LP, our general partner, will own the 2% general partner interest in us, as well as 65% of the incentive distribution rights, which entitle the holder to receive a higher percentage of cash distributed in excess of $0.5625 per unit in any quarter; - the WPP Group will own 25% of the incentive distribution rights and Arch Coal will own the remaining 10% of the incentive distribution rights; - we will own 100% of the membership interests in the operating company; and - the operating company will own 100% of the membership interests in its subsidiaries: NNG LLC, WPP LLC, GNP LLC and ACIN LLC. Our general partner has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, will conduct its business and operations and the board of directors and officers of GP Natural Resource Partners LLC will make decisions on behalf of us. Arch Coal owns a 42.25% membership interest in and is entitled to nominate three directors, including one independent director, of GP Natural Resource Partners LLC. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns a 57.75% membership interest in and is entitled to nominate five directors, including two independent directors, of GP Natural Resource Partners LLC. Corbin J. Robertson, Jr. controls each entity comprising the WPP Group. Mr. Robertson owns the general partner of Western Pocahontas Properties Limited Partnership, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman, Chief Executive Officer and controlling stockholder of New Gauley Coal Corporation. For additional disclosure regarding our formation and the negotiations that resulted in the division of responsibilities and ownership, please read "Certain Relationships and Related Transactions." The senior executives and other officers who currently manage Western Pocahontas Properties Limited Partnership will continue to manage us. They will remain employees of Western Pocahontas Properties Limited Partnership and will allocate varying percentages of their time to managing our operations. Neither our general partner, GP Natural Resource Partners LLC, nor their affiliates will receive any management fee or other compensation in connection with the management of our business but will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. The offices of Western Pocahontas Properties Limited Partnership are located at P.O. Box 2827, 1035 Third Avenue, Suite 300, Huntington, West Virginia 25727 and the telephone number is (304) 522-5757. Our principal executive offices are located at 601 Jefferson Street, Suite 3600, Houston, Texas 77002 and our phone number is (713) 751-7507. The chart on the following page depicts the organization and ownership of Natural Resource Partners after giving effect to the offering of the common units and the related formation transactions. 6 [Chart depicting the organization and ownership of Natural Resource Partners] 7 THE OFFERING Common units offered by us.... 2,598,750 common units. 2,988,563 common units if the underwriters exercise their over-allotment option from us in full. To the extent the underwriters exercise their over-allotment option, the net proceeds received by us from the sale of 57.75% of the additional units pursuant to the over-allotment option will be used to redeem common units from Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation. To the extent the underwriters do not exercise this over-allotment option in full, Great Northern Properties Limited Partnership and, under certain circumstances, New Gauley Coal Corporation, will purchase up to an aggregate of 75,503 additional common units from us. Common units offered by Arch Coal as the selling unitholder.................... 1,901,250 common units. 2,186,437 common units offered by Arch Coal if the underwriters exercise their over-allotment option in full. We will not receive any proceeds from the sale of common units by Arch Coal. Units outstanding after this offering...................... 11,353,658 common units and 11,353,658 subordinated units, each representing approximately a 49% limited partner interest in us. Cash distributions............ We intend to make minimum quarterly distributions of $0.5125 per common unit to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. In general, we will pay any cash distributions we make each quarter in the following manner: - first, 98% to the common units and 2% to the general partner, until each common unit has received a minimum quarterly distribution of $0.5125 plus any arrearages in the payment of the minimum quarterly distribution from prior quarters; - second, 98% to the subordinated units and 2% to the general partner, until each subordinated unit has received a minimum quarterly distribution of $0.5125; and - third, 98% to all units, pro rata, and 2% to the general partner, until each unit has received a distribution of $0.5625. If cash distributions per unit exceed $0.5625 in any quarter, the holders of the incentive distribution rights will receive, on a pro rata basis, a higher percentage of the cash we distribute in excess of that amount in increasing percentages up to an aggregate of 48%. We refer to these distributions as incentive distributions. We must distribute all of our cash on hand at the end of each quarter, after payment of fees and expenses, less reserves established by our general partner in its discretion. We refer to this cash as available cash, and we define its meaning in our partnership agreement and in the glossary in Appendix C. The 8 amount of available cash, if any, at the end of any quarter may be greater than or less than the minimum quarterly distribution. We believe, based on the assumptions beginning on page 44 of this prospectus, that we will have sufficient cash from operations to enable us to make the minimum quarterly distribution of $0.5125 on the common units and the subordinated units for each quarter through June 30, 2003. The amount of pro forma cash available for distribution generated during 2001 and the six months ended June 30, 2002 would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and 70.0% and 80.4%, respectively, of the minimum quarterly distribution on the subordinated units during these periods. Please read "Cash Available for Distribution" and Appendix D to this prospectus for the calculation of our ability to have paid the minimum quarterly distributions during these periods. Subordination period.......... During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before September 30, 2007. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. Early conversion of subordinated units......................... If we meet the financial tests in the partnership agreement for any quarter ending on or after September 30, 2005, 25% of the subordinated units will convert into common units. If we meet these tests for any quarter ending on or after September 30, 2006, an additional 25% of the subordinated units will convert into common units. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of subordinated units. Issuance of additional units......................... In general, during the subordination period we may issue up to 5,676,829 additional common units, or 50% of the common units outstanding immediately after this offering, without obtaining unitholder approval. We can also issue an unlimited number of common units for acquisitions that increase cash flow from operations per unit on a pro forma basis, and we can issue additional common units if the proceeds of the issuance are used to repay up to $25 million of certain of our indebtedness. Limited voting rights......... Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or the directors of GP Natural Resource Partners LLC on an annual or other regular basis. Our general partner may not be removed except by the vote of the holders of at least 66 2/3% of the outstanding units, including units owned by our general partner and its affiliates, 9 voting together as a single class. Upon the consummation of this offering, our general partner and its affiliates will own an aggregate of 80.2% of our common and subordinated units. This will give our general partner the practical ability to prevent its involuntary removal. Limited call right............ If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than their then current market price. Upon completion of this offering, our general partner and its affiliates will own 6,853,658, or 60.4%, of our outstanding common units and will not be able to exercise this call right. If we do not issue any equity securities prior to the expiration of the subordination period, upon the conversion of subordinated units into common units at the end of the subordination period, our general partner and its affiliates will own 80.2% of our outstanding common units and will be able to exercise this call right. Estimated ratio of taxable income to distributions....... We estimate that if you own the common units that you purchase in this offering through December 31, 2004 you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 60% of the cash distributed to you with respect to that period. A substantial portion of the income that will be allocated to you is expected to be long-term capital gain, which for individuals is subject to a significantly lower maximum federal income tax rate (currently 20%) than ordinary income (currently taxable at a maximum rate of 38.6%). If you are an individual taxable at the maximum rate of 38.6% on ordinary income, the effect of this lower capital gains rate is to produce an after tax return to you that is the same as if the amount of federal ordinary taxable income allocated to you for that period were less than 30% of the cash distributed to you for that period. Please read "Material Tax Consequences -- Tax Consequences of Unit Ownership -- Ratio of Taxable Income to Distributions" for the basis of this estimate. Exchange listing.............. Our common units have been approved for listing on the New York Stock Exchange, or NYSE, subject to official notice of issuance, under the symbol "NRP." 10 SUMMARY PRO FORMA FINANCIAL AND OPERATING DATA We derived the summary pro forma combined information by combining the historical financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and the Arch Coal Contributed Properties as of June 30, 2002 and for the six months ended June 30, 2002 and the year ended December 31, 2001. We adjusted the summary pro forma combined financial statements to reflect net assets and operations that are not being contributed to us. The pro forma as adjusted financial statements of Natural Resource Partners L.P. show the pro forma effect of the offering and the related transactions. We derived the summary pro forma as adjusted financial and operating data presented below as of June 30, 2002 and for the six months ended June 30, 2002 and the year ended December 31, 2001 from the unaudited pro forma combined financial statements. The pro forma as adjusted balance sheet assumes the offering and the related transactions occurred as of June 30, 2002, and the pro forma combined statements of revenues and direct costs and expenses assume that the offering and the related transactions occurred as of the beginning of the period presented. A more complete explanation of the pro forma adjustments can be found in "Notes to Pro Forma Financial Statements." We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the audited historical and the unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should read the table together with "Management's Discussion and Analysis of Financial Condition and Results of Operations." While the WPP Group will contribute substantially all of its coal royalty producing assets and operations to us, it will retain some assets and liabilities. 11 SUMMARY PRO FORMA FINANCIAL AND OPERATING DATA

YEAR ENDED SIX MONTHS ENDED DECEMBER 31, 2001 JUNE 30, 2002 ----------------------------- ---------------------------- PRO FORMA PRO FORMA PRO FORMA PRO FORMA COMBINED(A) AS ADJUSTED(B) COMBINED(A) AS ADJUSTED(B) ------------ -------------- ----------- -------------- (IN THOUSANDS, EXCEPT PRICE DATA) (UNAUDITED) REVENUES AND DIRECT COSTS AND EXPENSES DATA: REVENUES: Coal royalties................................... $42,433 $42,433 $ 22,775 $ 22,775 Gain on sale of property......................... 220 220 -- -- Lease and easement income........................ 381 381 -- -- Property taxes................................... 2,187 2,187 1,207 1,207 Other............................................ 2,028 2,028 1,263 1,263 ------- ------- -------- -------- Total revenues................................... 47,249 47,249 25,245 25,245 DIRECT COSTS AND EXPENSES: General and administrative(c).................... -- -- -- -- Taxes other than income.......................... 2,187 2,187 1,207 1,207 Depreciation, depletion and amortization......... 9,892 18,355 5,487 9,560 Other............................................ 283 283 411 411 ------- ------- -------- -------- Total expenses................................... 12,362 20,825 7,105 11,178 ------- ------- -------- -------- Excess of revenues over direct costs and expenses........................................... $34,887 $26,424 $ 18,140 $ 14,067 ======= ======= ======== ======== BALANCE SHEET DATA (AT PERIOD END): Total assets....................................... $220,962 $341,383 Long-term debt..................................... 46,531 -- Deferred revenue................................... 20,303 20,303 Total liabilities.................................. 66,834 20,303 Owners' equity/partners' capital(d)................ 154,128 321,080 OTHER DATA: Royalty coal tons produced by lessees.............. 28,990 28,990 13,735 13,735 Average gross coal royalty per ton................. $ 1.46 $ 1.46 $ 1.66 $ 1.66 OTHER FINANCIAL DATA: Estimated available cash from operating surplus(c)....................................... $40,379 $40,379 $ 21,427 $ 21,427

--------------- (a) We derived the pro forma combined information by adjusting the historical WPP Group amounts to reflect net assets and operations that are not being contributed to us and by adding the historical Arch Coal Contributed Properties amounts being contributed to us. We also eliminated historical general and administrative expenses for the WPP Group in order to reflect only the direct costs and expenses for its operations. (b) The pro forma as adjusted information was derived by adjusting the pro forma combined information for the offering and related transactions. (c) We define available cash and operating surplus under "Cash Distribution Policy." Estimated available cash from operating surplus includes annual general and administrative costs of $4.4 million that reflect our estimates of the costs of operating the properties contributed to us by the WPP Group and Arch Coal and the costs of being a publicly traded partnership. We base these estimates upon currently available information and they are subject to change. Please read "Cash Distribution Policy" and Appendix D. To the extent our general partner and its affiliates incur these costs on our behalf, we will reimburse them prior to making any distribution on the common units. (d) If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the common units at a price not less than their then market price. Upon completion of this offering, our general partner and its affiliates will own 60.4% of the outstanding common units. If we do not issue any equity securities prior to the expiration of the subordination period, upon the conversion of subordinated units into common units at the end of the subordination period, our general partner and its affiliates will own 80.2% of our outstanding common units and will be able to exercise this call right. 12 SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES NRP (GP) LP, our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in state statutes and judicial decisions and is commonly referred to as a "fiduciary" duty. Because our general partner and its general partner, GP Natural Resource Partners LLC, are owned by the WPP Group, Robertson Coal Management LLC and Arch Coal, however, the officers and directors of GP Natural Resource Partners LLC also have fiduciary duties to manage GP Natural Resource Partners LLC's and our general partner's business in a manner beneficial to the owners of the WPP Group, Robertson Coal Management LLC and to the stockholders of Arch Coal. The officers of GP Natural Resource Partners LLC have significant relationships with, and responsibilities to, the WPP Group, and the directors of GP Natural Resource Partners LLC have significant relationships with, and responsibilities to, the WPP Group, Robertson Coal Management LLC and Arch Coal. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary responsibilities of our general partner and GP Natural Resource Partners LLC, please read "Conflicts of Interest and Fiduciary Responsibilities." Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law. Although the WPP Group and Arch Coal have agreed in the omnibus agreement to restrictions on their ability to compete with us in the leasing of coal reserves, these restrictions are subject to numerous exceptions that will enable the WPP Group and Arch Coal to engage in substantial competition with us should they choose to do so. For a description of the terms of the omnibus agreement that contains these noncompete provisions, please read "Risk Factors -- The WPP Group and Arch Coal may engage in substantial competition with us" and "Certain Relationships and Related Transactions -- Omnibus Agreement." We will enter into four coal mining leases with Ark Land Company, a subsidiary of Arch Coal. Please read "Certain Relationships and Related Transactions -- Agreements with Ark Land Company" for a description of these leases. 13 RISK FACTORS Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially and adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment. RISKS RELATED TO OUR BUSINESS WE MAY NOT HAVE SUFFICIENT CASH FROM OPERATIONS TO PAY THE MINIMUM QUARTERLY DISTRIBUTION FOLLOWING ESTABLISHMENT OF CASH RESERVES AND PAYMENT OF FEES AND EXPENSES, INCLUDING PAYMENTS TO OUR GENERAL PARTNER. The amount of cash we can distribute on our units principally depends upon the amount of royalties we receive from our lessees, which will fluctuate from quarter to quarter based on, among other things: - the amount of coal our lessees are able to produce from our properties; - the price at which our lessees are able to sell coal; - the level of our operating costs, including payments to our general partner; and - prevailing economic conditions. In addition, the actual amount of cash we will have available for distribution will depend on other factors that include: - the costs of acquisitions, if any; - fluctuations in our working capital; - the level of capital expenditures we make; - the restrictions contained in our debt instruments and our debt service requirements; - our ability to borrow under our working capital facility to make distributions to our unitholders; and - the amount, if any, of cash reserves established by our general partner in its discretion. In determining the number of units and the minimum quarterly distribution, we have made the assumptions set forth in "Cash Available for Distribution" about the factors listed above. These assumptions are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we expect. If these assumptions are not realized, we may not be able to pay the minimum quarterly distribution or any amount on the common units or the subordinated units, in which event the market price of the common units may decline materially. You should also be aware that our ability to pay the minimum quarterly distribution each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common units, the subordinated units and the general partner interest to be outstanding immediately after the offering is approximately $47.5 million. If we had completed the transactions contemplated in this prospectus on January 1, 2001, estimated available cash from operating surplus generated during 2001 and 14 the six months ended June 30, 2002 would have been approximately $40.4 million and $21.4 million, respectively. These amounts would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and 70.0% and 80.4%, respectively, of the minimum quarterly distribution on the subordinated units during these periods. For a calculation of our ability to make distributions to unitholders based on our pro forma results, please read "Cash Available for Distribution" and Appendix D. A SUBSTANTIAL OR EXTENDED DECLINE IN COAL PRICES COULD REDUCE OUR COAL ROYALTY REVENUES AND THE VALUE OF OUR COAL RESERVES. The prices our lessees receive for their coal depend upon factors beyond their or our control, including: - the supply of and demand for domestic and foreign coal; - weather conditions; - the proximity to and capacity of transportation facilities; - worldwide economic conditions; - domestic and foreign governmental regulations and taxes; - the price and availability of alternative fuels; and - the effect of worldwide energy conservation measures. A substantial or extended decline in coal prices could materially and adversely affect us in two ways. First, lower prices may reduce the quantity of coal that may be economically produced from our properties. This, in turn, could reduce our coal royalty revenues and the value of our coal reserves. Second, even if production is not reduced, the royalties we receive on each ton of coal sold may be reduced. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of our coal reserves and any coal reserves that we may consider for acquisition. OUR LESSEES' COAL MINING OPERATIONS ARE SUBJECT TO OPERATING RISKS THAT COULD RESULT IN LOWER COAL ROYALTY REVENUES TO US. Our coal royalty revenues are largely dependent on our lessees' level of production from our coal reserves. The level of our lessees' production is subject to operating conditions or events beyond their or our control including: - the inability to acquire necessary permits or mining or surface rights; - changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit; - changes in governmental regulation of the coal industry or the electric utility industry; - mining and processing equipment failures and unexpected maintenance problems; - interruptions due to transportation delays; - adverse weather and natural disasters, such as heavy rains and flooding; - labor-related interruptions; and - fires and explosions. These conditions may increase our lessees' cost of mining and delay or halt production at particular mines either permanently or for varying lengths of time. Any interruptions to the production of coal from our reserves could reduce our coal royalty revenues. 15 WE DEPEND ON A LIMITED NUMBER OF PRIMARY OPERATORS FOR A SIGNIFICANT PORTION OF OUR COAL ROYALTY REVENUES, AND THE LOSS OF OR REDUCTION IN PRODUCTION FROM ANY OF OUR MAJOR OPERATORS COULD REDUCE OUR COAL ROYALTY REVENUES. We depend on a limited number of primary operators for a significant portion of our coal royalty revenues. In 2001, the following six operators and their subsidiaries, affiliates or contractors, accounted for approximately 84% of our coal royalty revenues: Arch Coal, Inc. (25%), Massey Energy Company (14%), CONSOL Energy Inc. (12.5%), Western Energy Company (12.5%), Resource Development L.L.C. (11%) and Peabody Energy Corporation (9%). Arch Coal, Massey Energy, Peabody Energy and CONSOL Energy each announced reduced production estimates for 2002, which in some cases have resulted in reduced production on some of our leases. Additionally, we are aware of proposed but unannounced reductions by some of our smaller lessees. If reductions in production by our lessees are implemented on our properties and sustained, our revenues may be substantially affected. Additionally, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us. WE MAY NOT BE ABLE TO TERMINATE OUR LEASES IF ANY OF OUR LESSEES DECLARE BANKRUPTCY, AND WE MAY EXPERIENCE DELAYS AND BE UNABLE TO REPLACE LESSEES THAT DO NOT MAKE ROYALTY PAYMENTS. A failure on the part of our lessees to make coal royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity. IF OUR LESSEES DO NOT MANAGE THEIR OPERATIONS WELL, THEIR PRODUCTION VOLUMES AND OUR COAL ROYALTY REVENUES COULD DECREASE. We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to: - marketing of the coal mined; - mine plans, including the amount to be mined and the method of mining; - processing and blending coal; - credit risk of their customers; - permitting; - 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. 16 If our lessees do not manage their operations well, their production could be reduced, which would result in lower coal royalty revenues to us. DUE TO OUR LACK OF ASSET DIVERSIFICATION, ADVERSE DEVELOPMENTS IN THE COAL INDUSTRY COULD REDUCE OUR COAL ROYALTY REVENUES. Our coal royalty business generates substantially all of our revenues. Due to our lack of asset diversification, an adverse development in the coal industry would have a significantly greater impact on our financial condition and results of operations than if we owned more diverse assets. ANY DECREASE IN THE DEMAND FOR METALLURGICAL COAL COULD RESULT IN LOWER COAL PRODUCTION BY OUR LESSEES, WHICH WOULD THEREBY REDUCE OUR COAL ROYALTY REVENUES. Our lessees produce a significant amount of the metallurgical coal that is used in both the U.S. and foreign steel industries. In 2001, approximately 12% of the coal production from our properties was metallurgical coal that was sold to the steel industry for the manufacture of coke. The steel industry has increasingly relied on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that our lessees mine could further decrease. Additionally, since the amount of steel that is produced is tied to global economic conditions, a decline in those conditions could result in the decline of steel, coke and coal production. Since metallurgical coal is priced higher than steam coal, some mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If they are unable to sell metallurgical coal, these mines may not be economically viable and may close. WE MAY NOT BE ABLE TO EXPAND AND OUR BUSINESS WILL BE ADVERSELY AFFECTED IF WE ARE UNABLE TO REPLACE OR INCREASE OUR RESERVES OR OBTAIN OTHER MINERAL RESERVES THROUGH ACQUISITIONS. Because our reserves decline as our lessees mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves or other mineral reserves that are economically recoverable. If we are unable to replace or increase our coal reserves or acquire other mineral reserves on acceptable terms, our royalty revenues will decline as our reserves are depleted. In addition, if we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our royalty revenues may decline and we could experience a material adverse effect on our business, financial condition or results of operations. If we acquire additional reserves, there is a possibility that any acquisition could be dilutive to earnings and reduce our ability to make distributions to unitholders. Any debt we incur to finance an acquisition may similarly affect our ability to make distributions to unitholders. Our ability to make acquisitions in the future also could be limited by restrictions under our existing or future debt agreements, competition from other mineral companies for attractive properties or the lack of suitable acquisition candidates. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Description of Credit Facility" for a discussion of restrictions on our ability to borrow funds to pay for acquisitions. 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. Domestic electric power generation accounts for approximately 90% of domestic coal consumption. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as natural gas, nuclear, fuel oil and hydroelectric power and environmental and other governmental regulations. We expect many new power plants will be built to produce electricity during peak periods of demand. Many of these new power plants will likely be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. As discussed under "-- Regulatory and Legal Risks," the increasingly stringent requirements of the Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired power plants. 17 CURRENT CONDITIONS IN THE COAL INDUSTRY MAY MAKE IT DIFFICULT FOR OUR LESSEES TO EXTEND EXISTING CONTRACTS OR ENTER INTO SUPPLY CONTRACTS WITH TERMS OF ONE YEAR OR MORE, WHICH COULD ADVERSELY AFFECT THE STABILITY AND PROFITABILITY OF THEIR OPERATIONS AND ADVERSELY AFFECT OUR COAL ROYALTY REVENUES. As electric utilities adjust to the Phase II requirements of the Clean Air Act and the possible deregulation of their industry, they are becoming increasingly less willing to enter into coal supply contracts with terms of more than one year. Instead, these utilities are purchasing higher percentages of coal on the spot market. The industry shift away from long-term supply contracts could adversely affect our lessees, and the level of our royalties, in several ways. First, fewer electric utilities will have a contractual obligation to purchase coal from our lessees, thereby increasing the risk that our lessees will not have a market for their coal production. Second, the prices our lessees receive in the spot market may be less than a contractual price an electric utility is willing to pay for a committed supply. Finally, spot market prices tend to be more volatile than contractual prices, which could result in decreased coal royalty revenues and adversely affect our ability to pay the minimum quarterly distribution in any one quarter. In addition, price adjustment, price reopener and other similar provisions in supply contracts with terms of one year or more may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Some coal supply contracts contain provisions which allow for the price at which coal is purchased to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price. In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiation leading to a significantly lower contract price could result in decreased coal royalty revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions. Some supply contracts also contain provisions which allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of specified events. These events typically include: - the inability of our lessees to deliver the volume or qualities of coal specified; - changes in the Clean Air Act rendering use of coal inconsistent with the customer's pollution control strategies; and - the occurrence of events beyond the reasonable control of the affected party, including labor disputes, mechanical malfunctions and changes in government regulations. COMPETITION WITHIN THE COAL INDUSTRY MAY ADVERSELY AFFECT THE ABILITY OF OUR LESSEES TO SELL COAL, AND EXCESS PRODUCTION CAPACITY IN THE INDUSTRY COULD PUT DOWNWARD PRESSURE ON COAL PRICES. Our lessees compete with numerous other coal producers in various regions of the United States for domestic sales. During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Any increases in coal prices could also encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our coal royalty revenues. Competition from coal with lower production costs shipped east from western coal mines has resulted in increased competition for coal sales in the Appalachian region and the Illinois Basin. This competition could result in decreased market share for our lessees operating in these regions and decreased coal royalty revenues to us. The amount of coal exported from the United States has declined over the last few years due to adverse economic conditions in Asia and the higher relative cost of U.S. coal due to the strength of the U.S. dollar. In addition, the recently imposed tariff on steel imports could exacerbate this decline in coal 18 exports. This decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on coal prices. LESSEES COULD SATISFY OBLIGATIONS TO THEIR CUSTOMERS WITH COAL FROM PROPERTIES OTHER THAN OURS, DEPRIVING US OF THE ABILITY TO RECEIVE AMOUNTS IN EXCESS OF MINIMUM ROYALTY PAYMENTS. Coal supply contracts do not generally require operators to satisfy their obligations to their customers with coal mined from specific reserves. Several factors may influence a lessee's decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee's lease with us, mining conditions, mining operations costs, cost and availability of transportation, and customer coal specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease and we will receive lower coal royalty revenues. FLUCTUATIONS IN TRANSPORTATION COSTS AND THE AVAILABILITY OR RELIABILITY OF TRANSPORTATION COULD REDUCE THE PRODUCTION OF COAL MINED FROM OUR PROPERTIES. Transportation costs represent a significant portion of the total cost of coal for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from coal producers in other parts of the country. Our lessees depend upon railroads, barges, trucks and beltlines to deliver coal to their customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair the ability of our lessees to supply coal to their customers. Our lessees' transportation providers may face difficulties in the future that may impair the ability of our lessees to supply coal to their customers, resulting in decreased coal royalty revenues to us. OUR RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY BE INACCURATE, WHICH COULD MATERIALLY ADVERSELY AFFECT THE QUANTITIES AND VALUE OF OUR RESERVES. Our reserve estimates may vary substantially from the actual amounts of coal our lessees may be able to economically recover from our reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to: - future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs; - future mining technology improvements; - the effects of regulation by governmental agencies; and - geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in areas where our lessees currently mine. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on the coal reserve data included in this prospectus. OUR LESSEES' WORK FORCES COULD BECOME INCREASINGLY UNIONIZED IN THE FUTURE. Eight mines on our properties are operated by unionized employees of our lessees or their affiliates. Our lessees' employees could become increasingly unionized in the future. Some labor unions active in our lessees' areas of operations are attempting to organize the employees of some of our lessees. If some or all 19 of our lessees' non-unionized operations were to become unionized, it could adversely affect their productivity, increase costs and increase the risk of work stoppages. In addition, our lessees' operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our lessees' operations. Any further unionization of our lessees' employees could adversely affect the stability of production from our reserves and reduce our coal royalty revenues. REGULATORY AND LEGAL RISKS OUR LESSEES ARE SUBJECT TO FEDERAL, STATE AND LOCAL LAWS AND REGULATIONS THAT MAY LIMIT THEIR ABILITY TO PRODUCE AND SELL COAL FROM OUR PROPERTIES. Our lessees may incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, including regulations and governmental enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our lessees' operations. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our lessees are pursued for these sanctions, costs and liabilities, their mining operations and, as a result, our coal royalty revenues, could be adversely affected. For example, in January 2002, the West Virginia Department of Environmental Protection entered an order finding a pattern of violations relating to water quality by Marfork Coal Company, a subsidiary of Massey Energy Company, and suspending its permit for operations adjacent to the Dorothy-Sarita property for 14 days. Marfork Coal filed an appeal and obtained a stay of enforcement of this order. The Surface Mining Board heard the appeal and reduced the suspension to nine days. Marfork Coal has appealed this decision to the circuit court and a hearing has been set for November 22, 2002. The circuit court has granted a stay of the suspension that will end 60 days following the November 22 hearing. The show cause order issued to Marfork Coal could also have an impact on the longwall mining operations of another subsidiary of Massey Energy, Performance Coal, that are conducted at the Eunice property because coal mined from this part of the Eunice property is sent to the Marfork Coal preparation plant for processing. If this show cause order is not resolved on favorable terms, the permits issued to Massey Energy and its subsidiaries could be suspended or revoked and production could be decreased at mines on the Dorothy-Sarita property and at the longwall mine operated by Performance Coal at the Eunice property, reducing our coal royalty revenues. If these permits are revoked, Massey Energy and its subsidiaries could be prohibited from obtaining additional permits. In the event of future violations at these properties or at other properties operated by these entities, the existence of those orders may increase the nature and gravity of any sanctions sought in the event that the state decides to pursue any enforcement. Recently, water from a mine operated by Marfork Coal has leaked through the subsurface strata, resulting in a discharge of water into water from a nearby creek. This discharge is from a mine that is not on our property, but it is possible that Marfork Coal could be subject to further enforcement actions that could impact its ability to continue mining on our property, or that this could be taken into account in connection with the show cause order discussed above. During its 2002 session, the West Virginia House of Representatives considered legislation that, if passed, would have significantly increased the scope of powers available to enforce the current weight restrictions on trucks carrying coal. Past sessions of the legislature have considered, but not adopted, similar legislation. The legislature and the governor appointed a task force to study the issue, and the task force issued a report recommending legislation that would raise the weight limits on the trucks, but would increase the number of required safety inspections and the amounts of registration fees and fines imposed for violations. The legislature has not yet acted on this recommendation. If increased enforcement of the existing weight restrictions continues, the costs of transporting coal in the state would increase. An increase 20 in transportation costs could have an adverse effect on our lessees' ability to increase or to maintain production on our properties and a similar adverse effect on our coal royalty revenues. Some species indigenous to our properties are protected under the Endangered Species Act. Federal and state legislation for the protection of endangered species may have the effect of prohibiting or delaying our lessees from obtaining mining permits and may include restrictions on road building and other mining activities in areas containing the affected species. Additional species on our properties may receive protected status, and currently protected species may be discovered within our properties. Either event could result in increased costs to us or our lessees. New environmental legislation and new regulations under existing environmental laws, including regulations to protect endangered species, could further regulate or tax the coal industry and may also require our lessees to change their operations significantly or to incur increased costs which could decrease our coal royalty revenues. Please read "Business -- Regulation." A SUBSTANTIAL PORTION OF OUR COAL HAS A HIGH SULFUR CONTENT. THIS COAL MAY BECOME MORE DIFFICULT TO SELL BECAUSE THE CLEAN AIR ACT RESTRICTS THE ABILITY OF ELECTRIC UTILITIES TO BURN HIGH SULFUR COAL. In 1995, Phase I of the Clean Air Act required high sulfur coal plants to reduce their emissions of sulfur dioxide to 2.5 pounds or less per million Btus, and in 2000, Phase II of the Clean Air Act tightened these sulfur dioxide restrictions further to 1.2 pounds of sulfur dioxide per million Btus. These restrictions may significantly reduce the demand by electric utilities for high sulfur coal. Currently, electric utilities operating coal-fired plants can purchase credits that allow them to comply with the sulfur dioxide emission compliance requirements. Many of the power plants supplied by our lessees do not currently have scrubbers. As of December 31, 2001, 75% of our coal reserves were not compliance coal. If our lessees' customers, or their potential customers in our market areas, choose not to purchase our noncompliance coal, our lessees may be unable to find other buyers for this coal at current price and volume levels, which could materially adversely affect our revenues and our ability to make distributions to our unitholders. See "Business -- Regulation -- Clean Air Act" for a description of the Phase II requirements of the Clean Air Act. A RECENT FEDERAL DISTRICT COURT RULING COULD PRECLUDE OUR LESSEES FROM OBTAINING CLEAN WATER ACT PERMITS REQUIRED FOR SOME OF THEIR FUTURE OPERATIONS AND COULD ALSO RESULT IN THE REVOCATION OF EXISTING PERMITS. On May 8, 2002, the United States District Court for the Southern District of West Virginia issued an order in Kentuckians for the Commonwealth v. Rivenburgh enjoining the Huntington, West Virginia office of the U.S. Army Corps of Engineers from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of overburden from mountaintop mining operations solely for the purpose of waste disposal. These valleys typically contain streams that, under the Clean Water Act, are considered navigable waters of the United States. The court held that the filling of these waters solely for waste disposal is a violation of the Clean Water Act. The effect of this injunction, if it is not overturned by an appellate court or subsequent legislation, will be to make mountaintop mining uneconomical in those areas subject to the injunction. We would be materially affected by this injunction because a substantial number of mountaintop mining valley fill permits required to be obtained by our lessees would need to be issued by the Huntington, West Virginia office of the U.S. Army Corps of Engineers. The court's injunction also prohibits the issuance of permits authorizing fill activities associated with types of mining activities other than mountaintop mining where the primary purpose or use of those fill activities is the disposal of waste. Such activities might include those associated with slurry impoundments and coal refuse disposal areas. If the injunction is not overturned by an appellate court or subsequent legislation, our lessees may not be able to obtain permits in many cases to use these common fill activities, which could render these operations uneconomical. Any consequent reduction or cessation of their operations would reduce mining on our properties and our royalty revenue. 21 Following the issuance of the court's May 8, 2002 order, the plaintiff in the Kentuckians case filed a motion for further injunctive relief requesting that the court require the Huntington, West Virginia office of the U.S. Army Corps of Engineers to revoke the Section 404 valley fill permit identified in the plaintiff's complaint. In addition, various defendants and intervenors filed motions seeking a clarification of the court's order, a stay pending appeal, and a dismissal for failure to join a necessary party. In response to the defendants' motion for clarification, the court decided that its injunction applies to any fill activity that does not have a "constructive primary purpose," citing as an example fills used solely for the disposal of waste. The court noted that such fills could include not only valley fills, but also other mining activities such as refuse impoundments, fills from standard contour or surface mines, or fills related to mine sites with "approximate original contour" waivers. The court noted, however, that determining whether a particular fill has a "constructive primary purpose" is up to the technical expertise of the U.S. Army Corps of Engineers. The court denied both the defendants' motion for stay pending appeal and their motion for dismissal. Both the U.S. Army Corps of Engineers and the industry parties that have intervened in the lawsuit have appealed this ruling to the Fourth Circuit Court of Appeals. We are unable to predict the ultimate outcome of this decision or the impact this decision may have on our lessees' operations and, therefore, our results of operations. The ruling could be upheld or reversed on appeal, settled by the parties or overturned by legislation, and this process could take several years to complete. If the decision is ultimately upheld in whole or in part on appeal, we cannot predict how it would be interpreted or implemented by the applicable governmental agencies or courts. Future litigation could result from ambiguities in the current order or ambiguities contained in future orders or decisions. In addition, although this ruling applies only to the Huntington, West Virginia office of the U.S. Army Corps of Engineers, future litigation, including appellate review of this case, could ultimately broaden its applicability to other offices of the U.S. Army Corps of Engineers, including offices which have issued and may issue in the future permits to our lessees for mining on our properties. We are also uncertain as to whether this ruling would impact only our lessees' future permits, or whether it would also apply to renewals of permits or to existing permits. If lawsuits challenging our lessees' permits were successful, our lessees would be required to suspend or cease their surface mining on our properties. If the decision is not overturned on appeal or by new legislation, we would suffer a material decrease in our royalty revenue. Please read "Business -- Regulation -- Clean Water Act." THE CLEAN AIR ACT AFFECTS THE END-USERS OF COAL AND COULD SIGNIFICANTLY AFFECT THE DEMAND FOR OUR COAL AND REDUCE OUR COAL ROYALTY REVENUES. The Clean Air Act and corresponding state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted from industrial boilers and power plants, including those that use our coal. These regulations constitute a significant burden on coal customers and stricter regulation could adversely affect the demand for and price of our coal, especially higher sulfur coal, resulting in lower coal royalty revenues. In July 1997, the U.S. Environmental Protection Agency adopted more stringent ambient air quality standards for particulate matter and ozone. Particulate matter includes small particles that are emitted during the coal combustion process. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA's position, although it remanded the EPA's ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA's adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that have not attained these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other by-products of coal combustion could restrict the market for coal and the development of new mines by our lessees. This 22 in turn may result in decreased production by our lessees and a corresponding decrease in our coal royalty revenues. Furthermore, in October 1998, the EPA finalized a rule that will require 19 states in the Eastern United States that have ambient air quality problems to make substantial reductions in nitrogen oxide emissions by the year 2004. To achieve these reductions, many power plants will be required to install additional control measures. The installation of these measures will make it more costly to operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel. Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned electric utility for alleged violations of the Clean Air Act. The EPA claims that the power plants operated by these utilities have failed to obtain permits required under the Clean Air Act for facility modifications. Our lessees supply coal to some of the affected utilities, and it is possible that other of our lessees' customers will be sued. These lawsuits could require the affected utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely affect their demand for coal. Any outcome that adversely affects our lessees' customers and their demand for coal could adversely affect our coal royalty revenues. Other proposed initiatives may have an effect upon our lessees' coal operations. One such proposal is the Bush Administration's recently announced Clear Skies Initiative. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power plants. Other so-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed in Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of air pollutants. Were such initiatives enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements. The Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by approximately 2009. These controls are likely to require significant new investments in controls by power plant owners. Like other environmental regulations, these standards and future standards could result in a decreased demand for coal. Please read "Business -- Regulation -- Clean Air Act." WE MAY BECOME LIABLE UNDER FEDERAL AND STATE MINING STATUTES IF OUR LESSEES ARE UNABLE TO PAY MINING RECLAMATION COSTS. The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and state statutes adopted pursuant to SMCRA impose various permitting and operational requirements on mine operators. In addition, SMCRA assigns to operators the responsibility of restoring the land to its approximate original contour or compensating the surface owner for types of damages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Regulatory authorities may attempt to assign the liabilities of our lessees to us if any of our lessees are not financially capable of fulfilling those obligations. Please read "Business -- Regulation." A RECENT FEDERAL DISTRICT COURT DECISION COULD LIMIT OUR LESSEES' ABILITY TO CONDUCT UNDERGROUND MINING OPERATIONS. On March 29, 2002, the U.S. District Court for the District of Columbia issued a ruling that could restrict underground mining activities conducted in the vicinity of public roads, within a variety of federally protected lands, within national forests and within a certain proximity of occupied dwellings. The lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to challenge regulations issued by the Department of Interior providing, among other things, that subsidence and underground activities that may lead to subsidence are not surface mining activities within the meaning of SMCRA. SMCRA generally 23 contains restrictions and certain prohibitions on the locations where surface mining activities can be conducted. The District Court entered summary judgment upon the plaintiffs' claims that the Secretary of the Interior's determination violated SMCRA. By order dated April 9, 2002, the court remanded the regulations to the Secretary of the Interior for reconsideration. None of the deep mining activities undertaken on our properties are within the federally protected lands or national forests where SMCRA restricts surface mining, or within any real proximity to occupied dwellings. However, this case poses a potential restriction on underground mining within 100 feet of a public road. If these SMCRA restrictions ultimately apply to underground mining, considerable uncertainty would exist about the nature and extent of this restriction. The significance of this decision for the coal mining industry remains unclear because this ruling is subject to appellate review. The Department of Interior and the National Mining Association, a trade group that intervened in this action, appealed the ruling and sought a stay of the order pending appeal to the U.S. Court of Appeals for the District of Columbia Circuit and the stay was granted. If the District Court's decision is not overturned, or if some legislative solution is not enacted, this ruling could have a material adverse affect on all coal mine operations that utilize underground mining techniques, including those of our lessees. While it may still be possible to obtain permits for underground mining operations in these areas, the time and expense of that permitting process are likely to increase significantly. RESTRUCTURING OF THE ELECTRIC UTILITY INDUSTRY COULD LEAD TO REDUCED COAL PRICES. A number of states and the District of Columbia have passed legislation to allow retail price competition in the electric utility industry. If ultimately implemented at both the state and federal levels, restructuring of the electric utility industry is expected to compel electric utilities to be more aggressive in developing and defending market share, to be more focused on their pricing and cost structures and to be more flexible in reacting to changes in the market. Congress is currently contemplating legislation that would further enhance competition in the electric industry. We believe that a fully competitive electricity market may put downward pressure on fuel prices, including coal, because electric utilities will be competing with other suppliers and will no longer necessarily be able to pass increased fuel costs on to their customers. In addition, some of these initiatives may or do mandate the increased use of alternative or renewable fuels as alternatives to burning fossil fuels. WE COULD BECOME LIABLE UNDER FEDERAL AND STATE SUPERFUND AND WASTE MANAGEMENT STATUTES. The Comprehensive Environmental Response, Compensation and Liability Act, known as CERCLA or "Superfund," and similar state laws create liabilities for the investigation and remediation of releases and threatened releases of hazardous substances to the environment and damages to natural resources. As landowners, we are potentially subject to liability for these investigation and remediation obligations. Please read "Business -- Regulation." RISKS RELATED TO OUR PARTNERSHIP STRUCTURE THE WPP GROUP AND ARCH COAL MAY ENGAGE IN SUBSTANTIAL COMPETITION WITH US. We rely on the employees of our general partner's affiliates, including the WPP Group, to conduct our business. Although the WPP Group and Arch Coal have agreed in the omnibus agreement to some restrictions on their ability to compete with us in the leasing of coal reserves, these restrictions are subject to numerous exceptions that will enable the WPP Group and Arch Coal to engage in substantial competition with us should they choose to do so. The restrictions on Arch Coal's ability to compete with us are materially less burdensome than the restrictions on the WPP Group. The partnership agreement provides that engaging in competitive activities by Arch Coal and the WPP Group that are not prohibited by the omnibus agreement will not constitute a breach of their fiduciary duties to us or the unitholders. To the extent that Arch Coal or the WPP Group competes with us, our growth prospects may be reduced and our results of operations and financial condition may be materially adversely affected. Furthermore, because they control us, the WPP Group and Arch Coal may have information regarding our operations 24 and business strategies that may give them an advantage in competing with us that a third-party competitor would not have. The exceptions to the noncompete obligations of the WPP Group and Arch Coal include the following: - The WPP Group or Arch Coal may lease their owned coal reserves within the United States to affiliates. For example, Arch Coal or an Arch Coal subsidiary may acquire new coal reserves and lease them directly to an operating subsidiary of Arch Coal and collect royalties on the lease without offering us the opportunity to acquire these reserves. - The WPP Group or Arch Coal may compete with us as long as the fair market value of the assets of any competing business are $10 million or less; provided, that with respect to the WPP Group, the total value of all competing businesses do not exceed $75 million. In addition, with respect to the WPP Group, any coal reserves that are owned and unleased at the time of the closing of the offering that are subsequently leased to third parties will not be considered in calculating the $75 million limitation. - In certain circumstances, the WPP Group and Arch Coal will be required to offer a competing business to us for purchase, but if they make a good faith decision in their sole discretion not to accept our offer, they will be able to continue to own and operate the business in competition with us. There is no provision in the omnibus agreement requiring the WPP Group or Arch Coal to sell the business to us at a fair market value determined by a third party investment banking firm or appraiser. - Arch Coal may buy an interest in a competing business that is a general partner interest or a managing member interest in a limited liability company provided it divests itself of such interest within six months of acquisition or it offers us the opportunity to buy its interest. If, however, Arch Coal is unable to divest its interest in the competing business within six months of acquisition despite a good faith, commercially reasonable attempt to do so, and Arch has not received an extension from our conflicts committee or has not offered us the opportunity to buy its competing interest, then Arch Coal may opt to either (1) have its designated directors immediately resign from the board of directors of our general partner, in which case Arch Coal may continue to own and operate the competing business but will continue to relinquish its rights to designate directors of our general partner until such time as it divests the competing business, or (2) hire an independent investment banking firm to determine the fair market value of the competing business. If Arch Coal elects to obtain an independent valuation of its competing business, then: - if Arch Coal and our general partner (with the concurrence of the conflicts committee) agree upon the price of the competing business, our partnership will purchase the competing business; - if Arch Coal seeks to sell the competing business to our partnership at the price determined by the investment banking firm and our general partner (with the concurrence of the conflicts committee) declines to purchase the competing business, Arch Coal will be free to continue to own and operate the competing business; - if Arch Coal does not wish to sell the competing business to our partnership at the price determined by the investment banking firm and our general partner (with the concurrence of the conflicts committee) seeks to purchase the competing business at such price, then Arch Coal's designated directors must immediately resign from the board of directors of our general partner, in which case Arch Coal may continue to own and operate the competing business. Arch Coal will continue to relinquish its rights to designate directors to our general partner until it divests the competing business. - There is no restriction on the ability of the WPP Group and Arch Coal to compete with us in the ownership and operation of other businesses, including the leasing of other mineral properties such 25 as oil and gas and iron ore. It is our strategy to diversify into the acquisition of mineral properties in addition to coal properties. - There is no restriction on the ability of the WPP Group and Arch Coal to own a noncontrolling equity interest in a competing business, including an economic stake that is greater than their stake in us. If the WPP Group or Arch Coal, as applicable, ceases to participate in the control of our general partner, then it will no longer be bound by the noncompetition provisions of the omnibus agreement. Please see "Certain Relationships and Related Transactions -- Omnibus Agreement" for a description of the omnibus agreement. THE WPP GROUP, ARCH COAL AND THEIR AFFILIATES HAVE CONFLICTS OF INTEREST AND LIMITED FIDUCIARY RESPONSIBILITIES, WHICH MAY PERMIT THEM TO FAVOR THEIR OWN INTERESTS TO YOUR DETRIMENT. Following the offering, the WPP Group, Arch Coal and their affiliates will own an aggregate of 80.2% of our common and subordinated units and together will own and control our general partner. Conflicts of interest may arise between the WPP Group, Arch Coal and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of the unitholders. These conflicts include, among others, the following situations: - Some officers of the WPP Group, who will provide services to us, will also devote significant time to the businesses of the WPP Group and will be compensated by the WPP Group for the services they provide. Please read "Management -- Directors and Executive Officers of GP Natural Resource Partners LLC." - Neither the partnership agreement nor any other agreement requires the WPP Group or Arch Coal to pursue a business strategy that favors us. The directors and officers of the WPP Group have a fiduciary duty to make decisions in the best interests of the WPP Group's limited partners and shareholders, and Arch Coal's directors and officers have a fiduciary duty to make decisions in the best interests of Arch Coal's shareholders. - As described above, the WPP Group and its affiliates and Arch Coal and its affiliates may engage in substantial competition with us. - Our general partner is allowed to take into account the interests of parties other than us, such as the WPP Group and Arch Coal, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to the unitholders. - Our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law. - Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional limited partner interests and reserves, each of which can affect the amount of cash that is distributed to unitholders. - Our general partner determines which costs incurred by it and its affiliates are reimbursable by us. - Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf. - Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates. 26 - Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. - In some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period. Please read "Certain Relationships and Related Transactions -- Omnibus Agreement" and "Conflicts of Interest and Fiduciary Responsibilities." EVEN IF UNITHOLDERS ARE DISSATISFIED, THEY CANNOT EASILY REMOVE OUR GENERAL PARTNER. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of GP Natural Resource Partners LLC and will have no right to elect our general partner or the board of directors of GP Natural Resource Partners LLC on an annual or other continuing basis. The board of directors of GP Natural Resource Partners LLC is elected by Robertson Coal Management LLC, which is wholly owned by Corbin J. Robertson, Jr., our chief executive officer and chairman and an affiliate of the WPP Group, and by Arch Coal. Robertson Coal Management LLC has the right to elect five members and Arch Coal has the right to elect three members of the board. Although our general partner has a fiduciary duty to manage our business in a manner beneficial to us and the unitholders, the directors of GP Natural Resource Partners LLC have a fiduciary duty to manage the general partner in a manner beneficial to its members, Robertson Coal Management LLC and Arch Coal. Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. Because affiliates of the general partner will control approximately 80.2% of all the outstanding units, the general partner currently cannot be removed without the consent of the general partner and its affiliates. Also, if our general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders' dissatisfaction with the general partner's performance in managing our partnership will most likely result in the termination of the subordination period. Furthermore, unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management. As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the takeover price. 27 THE CONTROL OF OUR GENERAL PARTNER MAY BE TRANSFERRED TO A THIRD PARTY WITHOUT UNITHOLDER CONSENT. Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owners of our general partner or its general partner, GP Natural Resource Partners LLC, from transferring their ownership interest in the general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers. OUR GENERAL PARTNER'S ABSOLUTE DISCRETION IN DETERMINING THE LEVEL OF CASH RESERVES MAY ADVERSELY AFFECT OUR ABILITY TO MAKE CASH DISTRIBUTIONS TO UNITHOLDERS. Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will reduce the amount of cash available for distribution to unitholders. YOU WILL EXPERIENCE IMMEDIATE AND SUBSTANTIAL DILUTION OF $6.14 PER COMMON UNIT. The assumed initial public offering price of $20.00 per unit exceeds pro forma net tangible book value of $13.86 per unit. Based on the assumed initial public offering price, you will incur immediate and substantial dilution of $6.14 per common unit. The main factor causing dilution is that our general partner and its affiliates acquired interests in us at equivalent per unit prices less than the public offering price. Please read "Dilution." WE MAY ISSUE ADDITIONAL COMMON UNITS WITHOUT YOUR APPROVAL, WHICH WOULD DILUTE YOUR EXISTING OWNERSHIP INTERESTS. During the subordination period, our general partner may cause us to issue up to 5,676,829 additional common units without your approval. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without your approval, in a number of circumstances, such as: - the issuance of common units in connection with acquisitions or capital improvements that our general partner determines would increase cash flow from operations per unit on a pro forma basis; - the conversion of subordinated units into common units; - the conversion of units of equal rank with the common units into common units under some circumstances; - the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner; - the issuance of common units under our incentive plans; or - issuances of common units to repay up to $25 million of certain indebtedness. After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of the unitholders. Our partnership agreement does not give the unitholders the right to approve our issuance at any time of equity securities ranking junior to the common units. 28 The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: - your proportionate ownership interest in us will decrease; - the amount of cash available for distribution on each unit may decrease; - because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by the common unitholders will increase; - the relative voting strength of each previously outstanding unit may be diminished; and - the market price of the common units may decline. COST REIMBURSEMENTS DUE OUR GENERAL PARTNER MAY BE SUBSTANTIAL AND WILL REDUCE THE CASH AVAILABLE FOR DISTRIBUTION TO YOU. Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including GP Natural Resource Partners LLC and the officers and directors of GP Natural Resource Partners LLC, for all expenses they incur on our behalf. Please read "Conflicts of Interest and Fiduciary Responsibilities -- Conflicts of Interest." The reimbursement of expenses could adversely affect our ability to pay cash distributions to you. Please read "Certain Relationships and Related Transactions." Our general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us with other services for which we will be charged fees as determined by our general partner. Excluding reimbursements for costs and expenses associated with this offering and the related transactions, we estimate that the total amount of the reimbursements and fees will be approximately $4.4 million in the first year following this offering. OUR GENERAL PARTNER HAS A LIMITED CALL RIGHT THAT MAY REQUIRE YOU TO SELL YOUR UNITS AT AN UNDESIRABLE TIME OR PRICE. If, at any time, our general partner and its affiliates own more than 80% of the common units then outstanding, our general partner has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units at a price not less than the then-current market price of the units. If we do not issue any equity securities prior to the expiration of the subordination period, upon the conversion of subordinated units into common units at the end of the subordination period, our general partner and its affiliates will own 80.2% of our outstanding common units and will be able to exercise this call right. As a result, you may be required to sell your common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur tax liability upon a sale of your units. For further information about the call right, please read "The Partnership Agreement -- Limited Call Right." YOUR LIABILITY MAY NOT BE LIMITED IF A COURT FINDS THAT UNITHOLDER ACTION CONSTITUTES CONTROL OF OUR BUSINESS. A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. While our partnership is organized under Delaware law, we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for our obligations as if you were a general partner if: - a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or 29 - your right to act with other unitholders to remove or replace the general partner, to approve some amendment to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. Please read "The Partnership Agreement -- Limited Liability" for a discussion of the implications of the limitations on the liability of a unitholder. TAX RISKS TO COMMON UNITHOLDERS You should read "Material Tax Consequences" for a full discussion of the expected material federal income tax consequences of owning and disposing of common units. THE IRS COULD TREAT US AS A CORPORATION FOR TAX PURPOSES, WHICH WOULD SUBSTANTIALLY REDUCE THE CASH AVAILABLE FOR DISTRIBUTION TO YOU. The after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you may be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. If we were treated as a corporation there would be a material reduction in the after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us. A SUCCESSFUL IRS CONTEST OF THE FEDERAL INCOME TAX POSITIONS WE TAKE MAY ADVERSELY AFFECT THE MARKET FOR OUR COMMON UNITS, AND THE COST OF ANY IRS CONTEST WILL BE BORNE BY OUR UNITHOLDERS AND OUR GENERAL PARTNER. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with all of our counsel's conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution. YOU MAY BE REQUIRED TO PAY TAXES ON INCOME FROM US EVEN IF YOU DO NOT RECEIVE ANY CASH DISTRIBUTIONS FROM US. You will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not 30 receive cash distributions from us equal to your share of our taxable income or even the tax liability that results from that income. TAX GAIN OR LOSS ON DISPOSITION OF COMMON UNITS COULD BE DIFFERENT THAN EXPECTED. If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. TAX-EXEMPT ENTITIES, REGULATED INVESTMENT COMPANIES AND FOREIGN PERSONS FACE UNIQUE TAX ISSUES FROM OWNING COMMON UNITS THAT MAY RESULT IN ADVERSE TAX CONSEQUENCES TO THEM. Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, some of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, may be unrelated business taxable income and will be taxable to such a unitholder. Very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding tax at the highest effective tax rate applicable to individuals, and non-U.S. unitholders will be required to file federal income tax returns and pay tax on their share of our taxable income. WE WILL REGISTER AS A TAX SHELTER. THIS MAY INCREASE THE RISK OF AN IRS AUDIT OF US OR YOU. We intend to register with the IRS as a "tax shelter." The federal income tax laws require that some types of entities, including some partnerships, register as tax shelters in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments may be made. Any unitholder owning less than a 1% profit interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in your tax returns and may lead to audits of your tax returns and adjustments of items unrelated to us. You would bear the cost of any expense incurred in connection with an examination of your tax return. YOU WILL LIKELY BE SUBJECT TO STATE AND LOCAL TAXES IN STATES WHERE YOU DO NOT LIVE AS A RESULT OF AN INVESTMENT IN UNITS. In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and do business in Alabama, Illinois, Indiana, Kentucky, Maryland, Montana, Virginia and West Virginia. Each of these states currently imposes a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units. 31 USE OF PROCEEDS We expect to receive net proceeds of approximately $50.1 million from the sale of 2,674,253 common units offered by this prospectus, after deducting underwriting discounts but before paying estimated offering expenses. We base these proceeds on an assumed public offering price of $20.00 per common unit, an assumed purchase of 75,503 common units by New Gauley Coal Corporation and Great Northern Properties Limited Partnership and no exercise of the underwriters' over-allotment option. We will not receive any proceeds from the sale of the common units by Arch Coal. We anticipate using the aggregate net proceeds of this offering to: - repay $46.5 million of debt we will assume from the WPP Group consisting of: - $36.0 million assumed from Western Pocahontas Properties Limited Partnership, of which $30.0 million was incurred with the purchase of CSX's reversionary interest in March 2002; - $1.5 million assumed from New Gauley Coal Corporation; - $9.0 million assumed from Great Northern Properties Limited Partnership; - pay $2.8 million for expenses associated with the offering and related transactions; - fund working capital of $0.6 million; and - distribute $0.1 million to the WPP Group. In addition, Arch Coal will contribute $0.8 million to us to pay $0.4 million for its share of deferred financing costs and to fund $0.4 million in working capital. If the underwriters do not exercise any portion of their over-allotment option, Great Northern Properties Limited Partnership and, in certain circumstances, New Gauley Coal Corporation, will purchase up to an aggregate of 75,503 additional common units from us at the assumed initial public offering price of $20.00 per unit. We will receive net proceeds of $1.5 million from such sale, which will not be reduced by the underwriting discount. If the underwriters exercise their over-allotment option in full, we will sell 389,813 units (57.75% of the total over-allotment option) for net proceeds of $7.3 million and Arch Coal will sell 285,187 units (42.25% of the total over-allotment option) for net proceeds of $5.3 million. We will use our net proceeds from this exercise to redeem 312,924 common units from Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation in reimbursement of capital expenditures made by them, and we will use the remainder to repay indebtedness assumed from New Gauley Coal Corporation and Great Northern Properties Limited Partnership. As of June 30, 2002, $6.0 million of the debt to be repaid by Western Pocahontas Properties Limited Partnership bore interest at 7.6% and matures in April 2013 and $30.0 million bore interest at 4.91% and matures in March 2012; the debt to be repaid by New Gauley Coal Corporation bore interest at 7.6% and matures in April 2013; and the debt to be repaid by Great Northern Properties Limited Partnership bore interest at 4.6% and matures in September 2004. 32 CAPITALIZATION The following table shows (1) our historical capitalization as of June 30, 2002 on an actual basis and (2) our pro forma capitalization as of June 30, 2002, as adjusted to reflect the offering of the common units and the application of the net proceeds in the manner described under "Use of Proceeds." This table is derived from, should be read in conjunction with, and is qualified in its entirety by reference to, our historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read the table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

AT JUNE 30, 2002 ----------------------- PRO FORMA PRO FORMA COMBINED AS ADJUSTED --------- ----------- (IN THOUSANDS) Cash and cash equivalents................................... $ -- $ 1,000 ======== ======== Long-term debt(a)........................................... $ 46,531 $ -- Owners' equity/partners' capital: Owners' equity............................................ 154,128 -- Common unitholders........................................ -- 148,578 Subordinated unitholders.................................. -- 165,737 General partner........................................... -- 6,765 -------- -------- Total owners' equity/partners' capital................. 154,128 321,080 -------- -------- Total capitalization........................................ $200,659 $321,080 ======== ========

--------------- (a) $92.5 million in long-term debt will be retained by the WPP Group following the offering. 33 DILUTION Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2002, after giving effect to the offering of common units and the related transactions, our net tangible book value was $321.1 million, or $13.86 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table: Assumed initial public offering price per common unit.............. $20.00 Pro forma net tangible book value per common unit before the offering(1)............................................... $7.49 Increase in net tangible book value per common unit attributable to purchasers in the offering................ 6.37 ----- Less: Pro forma net tangible book value per common unit after the offering(2)...................................................... 13.86 ------ Immediate dilution in tangible net book value per common unit to new investors.................................................... $ 6.14 ====== --------------- (1) Determined by dividing the number of units to be issued to affiliates of our general partner (8,754,908 common units, 11,353,658 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 463,415 units) for their contribution of assets and liabilities to us into the net pro forma tangible book value of the contributed assets and liabilities. (2) Determined by dividing the total number of units to be outstanding after the offering and the related transactions (11,353,658 common units, 11,353,658 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 463,415 units) into our pro forma net tangible book value, after giving effect to the application of the net proceeds of the offering and the related transactions. The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

UNITS ACQUIRED -------------------- TOTAL NUMBER PERCENT CONSIDERATION PERCENT ---------- ------- -------------- ------- (IN THOUSANDS) General partner and its affiliates(1)(2)....................... 20,571,981 88.8% $274,059 84.1% New investors............................ 2,598,750 11.2% 51,975 15.9% ---------- ------ -------- ------ Total.................................. 23,170,731 100.0% $326,034 100.0% ========== ====== ======== ======

--------------- (1) The units acquired by the general partner and its affiliates consist of 8,754,908 common units, including 75,503 common units acquired by affiliates if the underwriters' over-allotment option is not exercised, 11,353,658 subordinated units and the 2% general partner interest, having a dilutive effect equivalent to 463,415 units. (2) The net assets contributed by the WPP Group were recorded at historical cost and the net assets contributed by Arch Coal were recorded at their fair values. The value of the consideration provided by our general partner and its affiliates, as of June 30, 2002, after giving effect to the application of the net proceeds of the offering, is as follows:

(IN THOUSANDS) Historical book value of net assets contributed excluding assets and liabilities retained -- WPP Group.............. $ 77,621 Historical book value of net assets contributed excluding assets and liabilities retained -- Arch Coal.............. 76,507 Fair value adjustments for Arch Coal........................ 118,421 Additional units purchased by New Gauley Coal Corporation and Great Northern Properties Limited Partnership......... 1,510 -------- $274,059 ========

34 CASH DISTRIBUTION POLICY QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH General. Within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2002, we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through December 31, 2002 based on the actual length of the period. Definition of Available Cash. We define available cash in the glossary, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter: - less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or appropriate to: - provide for the proper conduct of our business; - comply with applicable law, any of our debt instruments or other agreements; or - provide funds for distributions to our unitholders and our general partner for any one or more of the next four quarters; - plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.5125, or $2.05 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. There is no guarantee, however, that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or if an event of default is existing, under our credit facility. OPERATING SURPLUS AND CAPITAL SURPLUS General. All cash distributed to unitholders will be characterized as either "operating surplus" or "capital surplus." We distribute available cash from operating surplus differently than available cash from capital surplus. Maintenance capital expenditures are capital expenditures made to maintain, over the long term, the operating capacity of our assets as they existed at the time of the expenditure. Expansion capital expenditures are capital expenditures made to increase over the long term the operating capacity of our assets as they existed at the time of the expenditure. The general partner has the discretion to determine how to allocate a capital expenditure for the acquisition or expansion of coal reserves between maintenance capital expenditures and expansion capital expenditures, and its good faith allocation will be conclusive. Maintenance capital expenditures reduce operating surplus, from which we pay the minimum quarterly distribution, but expansion capital expenditures do not. Definition of Operating Surplus. We define operating surplus in the glossary, and it generally means: - our cash balance on the closing date of this offering; plus - $15.0 million (as described below); plus - all of our cash receipts after the closing of this offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus 35 - working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for that quarter; less - all of our operating expenditures after the closing of this offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less - the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures. Definition of Capital Surplus. We also define capital surplus in the glossary, and it will generally be generated only by: - borrowings other than working capital borrowings; or - sales of debt and equity securities; or - sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets. Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $15.0 million in addition to our cash balance on the closing date of this offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $15.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus. SUBORDINATION PERIOD General. During the subordination period, which we define below and in the glossary, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.5125 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. Definition of Subordination Period. We define the subordination period in the glossary. The subordination period will extend until the first day of any quarter beginning after September 30, 2007 that each of the following tests are met: - distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; - the "adjusted operating surplus" (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and - there are no arrearages in payment of the minimum quarterly distribution on the common units. 36 Early Conversion of Subordinated Units. Before the end of the subordination period, 50% of the subordinated units, or up to 5,676,829 subordinated units, will convert into common units on a one-for-one basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after: - September 30, 2005, with respect to 25% of the subordinated units; and - September 30, 2006, with respect to 25% of the subordinated units. The early conversions will occur if at the end of the applicable quarter each of the following occurs: - distributions of available cash from operating surplus on each of the outstanding common units and the subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; - the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and - there are no arrearages in payment of the minimum quarterly distribution on the common units. The second early conversion of the subordinated units may not occur, however, until at least one year following the first early conversion of the subordinated units. Definition of Adjusted Operating Surplus. We define adjusted operating surplus in the glossary and for any period it generally means: - operating surplus generated with respect to that period; less - any net increase in working capital borrowings with respect to that period; less - any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus - any net decrease in working capital borrowings with respect to that period; plus - any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net reductions of reserves of cash generated in prior periods. Effects of Expiration of Subordination Period. Upon expiration of the subordination period, all remaining subordinated units will convert into common units on a one-for-one basis and will then participate, pro rata, with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of that removal: - the subordination period will end and each subordinated unit will immediately convert into one common unit; - any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and - the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests. 37 DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS DURING THE SUBORDINATION PERIOD We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner: - First, 98% to the common unitholders, pro rata, and 2% to our general partner, until we have distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; - Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we have distributed for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; - Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we have distributed for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and - Thereafter, in the manner described in "-- Incentive Distribution Rights" below. DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS AFTER THE SUBORDINATION PERIOD We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner: - First, 98% to all unitholders, pro rata, and 2% to the general partner, until we have distributed for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and - Thereafter, in the manner described in "-- Incentive Distribution Rights" below. INCENTIVE DISTRIBUTION RIGHTS Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner, the members of the WPP Group and Arch Coal currently hold 65%, 25% and 10%, respectively, of the incentive distribution rights. The WPP Group and Arch Coal may transfer these rights, but our general partner may only transfer these rights separately from its general partner interest in accordance with restrictions in the partnership agreement. If for any quarter: - we have distributed available cash from operating surplus on each common unit and subordinated unit in an amount equal to the minimum quarterly distribution; and - we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution; then we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner: - First, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder has received a total of $0.5625 per unit for that quarter (the "first target distribution"); - Second, 85% to all unitholders, and 13% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner, until each unitholder has received a total of $0.6625 per unit for that quarter (the "second target distribution"); - Third, 75% to all unitholders, and 23% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner, until each unitholder has received a total of $0.7625 per unit for that quarter (the "third target distribution"); and 38 - Thereafter, 50% to all unitholders and 48% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner. In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. PERCENTAGE ALLOCATIONS OF AVAILABLE CASH FROM OPERATING SURPLUS The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders, our general partner and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of the unitholders, our general partner and the holders of the incentive distribution rights in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until available cash we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

MARGINAL PERCENTAGE INTEREST IN DISTRIBUTIONS ------------------------------------ HOLDERS OF TOTAL QUARTERLY INCENTIVE DISTRIBUTION TARGET GENERAL DISTRIBUTION AMOUNT UNITHOLDERS PARTNER RIGHTS ------------------- ----------- ------- ------------ Minimum Quarterly Distribution.................. $0.5125 98% 2% -- First Target Distribution....... $0.5125 up to $0.5625 98% 2% -- Second Target Distribution...... above $0.5625 up to $0.6625 85% 2% 13% Third Target Distribution....... above $0.6625 up to $0.7625 75% 2% 23% Thereafter...................... above $0.7625 50% 2% 48%

DISTRIBUTIONS FROM CAPITAL SURPLUS How Distributions from Capital Surplus Will Be Made. We will make distributions of available cash from capital surplus, if any, in the following manner: - First, 98% to all unitholders, pro rata, and 2% to the general partner, until we have distributed for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price; - Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we have distributed for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and - Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus. Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. Any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied, however, to the payment of the minimum quarterly distribution or any arrearages. 39 Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of the incentive distribution rights and 2% to our general partner. ADJUSTMENT OF MINIMUM QUARTERLY DISTRIBUTION AND TARGET DISTRIBUTION LEVELS In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust: - the minimum quarterly distribution; - the target distribution levels; - the unrecovered initial unit price; - the number of common units issuable during the subordination period without a unitholder vote; and - the number of common units into which a subordinated unit is convertible. For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property. In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we become subject to a maximum combined marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distribution levels would each be reduced to 62% of their previous levels. DISTRIBUTIONS OF CASH UPON LIQUIDATION If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation. The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. There may not be sufficient gain upon our liquidation, however, to enable the holder of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner. 40 Manner of Adjustment for Gain. The manner of the adjustment is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner: - First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances; - Second, 98% to the common unitholders, pro rata, and 2% to our general partner until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; plus (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; plus (3) any unpaid arrearages in payment of the minimum quarterly distribution; - Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; - Fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that was distributed 98% to the unitholders, pro rata, and 2% to our general partner for each quarter of our existence; - Fifth, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that was distributed 85% to the unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner for each quarter of our existence; - Sixth, 75% to all unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that was distributed 75% to the unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata and 2% to our general partner for each quarter of our existence; and - Thereafter, 50% to all unitholders, pro rata, and 48% to the holders of the incentive distribution rights, pro rata, and 2% to our general partner. 41 If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable. Manner of Adjustment for Losses. Upon our liquidation, we will generally allocate any loss to the general partner and the unitholders in the following manner: - First, 98% to holders of subordinated units, pro rata, and 2% to the general partner, until the capital accounts of the holders of the subordinated units have been reduced to zero; - Second, 98% to the holders of common units, pro rata, and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and - Thereafter, 100% to the general partner. If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that the first bullet point above will no longer be applicable. Adjustments to Capital Accounts upon the Issuance of Additional Units. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the general partner's capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. 42 CASH AVAILABLE FOR DISTRIBUTION We intend to pay each quarter, to the extent we have sufficient available cash from operating surplus including working capital borrowings, the minimum quarterly distribution of $0.5125 per unit, or $2.05 per year, on all the common units and subordinated units. Available cash for any quarter will consist generally of all cash on hand at the end of that quarter, plus working capital borrowings after the end of the quarter, as adjusted for reserves. Operating surplus generally consists of cash on hand at closing, cash generated from operations after deducting related expenditures and other items, plus working capital borrowings after the end of the quarter, plus $15.0 million, as adjusted for reserves. The definitions of available cash and operating surplus are in the glossary. The amount of available cash from operating surplus needed to pay the minimum quarterly distribution for two quarters and for four quarters on the common units and the subordinated units and to pay the related distribution on the general partner interest to be outstanding immediately after this offering are approximately:

TWO QUARTERS FOUR QUARTERS ------------ ------------- (IN THOUSANDS) Common units................................................ $11,637.5 $23,275.0 Subordinated units.......................................... 11,637.5 23,275.0 2% general partner interest................................. 475.0 950.0 --------- --------- Total..................................................... $23,750.0 $47,500.0 ========= =========

ESTIMATED AVAILABLE CASH FROM OPERATING SURPLUS DURING 2001 WOULD NOT HAVE BEEN SUFFICIENT TO PAY THE MINIMUM QUARTERLY DISTRIBUTION ON ALL UNITS. If we had completed the transactions contemplated in this prospectus on January 1, 2001, our pro forma available cash from operating surplus generated during 2001 and the six months ended June 30, 2002 would have been approximately $44.8 million and $23.6 million, respectively. Pro forma available cash from operating surplus excludes any expenses associated with the reversionary interest purchased by Western Pocahontas Properties Limited Partnership in December 2001 and March 2002 and eliminates general and administrative expenses in order to reflect only the direct costs and expenses for our operations. Estimated available cash from operating surplus includes general and administrative expenses, such as cost of tax return preparation, accounting support services, annual and quarterly reports to unitholders, investor relations and registrar and transfer agents fees, of approximately $1.5 million per year that we expect to incur as a result of being a publicly traded partnership and also includes approximately $2.9 million per year of general and administrative expenses that we will incur related to our operation of the properties contributed to us by the WPP Group and Arch Coal. Our estimated available cash from operating surplus generated during 2001 and the six months ended June 30, 2002 would have been approximately $40.4 million and $21.4 million, respectively. These amounts would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and approximately 70.0% and 80.4%, respectively, of the minimum quarterly distribution on the subordinated units during these periods. Our pro forma excess of revenues over direct costs and expenses comes from our pro forma financial statements. The pro forma financial statements do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, available cash from operating surplus as defined in the partnership agreement is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. A more complete explanation of the pro forma adjustments can be found in the Notes to Pro Forma Financial Statements for Natural Resource Partners. We derived the amounts of estimated available cash from operating surplus shown above in the manner described in Appendix D. As a result, the amount of estimated available cash from operating surplus should only be viewed as a general indication of the amount of available cash from operating surplus that we might have generated had we been formed in earlier periods. 43 WE BELIEVE WE WILL HAVE SUFFICIENT AVAILABLE CASH FROM OPERATING SURPLUS FOLLOWING THE OFFERING TO PAY THE MINIMUM QUARTERLY DISTRIBUTION ON ALL UNITS THROUGH JUNE 30, 2003. We believe that we will have sufficient available cash from operating surplus to allow us to make the full minimum quarterly distribution on all the common units and subordinated units for each quarter through June 30, 2003. Our belief is based on a number of general business assumptions that include: - we will not be obligated to make any unexpected cash payments associated with post-mine reclamation, workers' compensation claims or environmental litigation or cleanup; - there will be no changes in federal, state or local environmental, regulatory or tax laws or the enforcement or interpretation thereof that would materially affect our lessees' operations; - none of our lessees will have their permits to mine our properties revoked or suspended; - we will not experience any unanticipated loss of, or material changes in the terms of, any material lease with a lessee and our lessees will perform their obligations under their leases with us; - our lessees will not experience any labor or industrial disputes or other disturbances or disputes that would materially affect our operations; - our lessees will not have any major mine-related accidents or production interruptions; - we will not make any acquisitions or dispositions of assets; and - there will not be any material adverse change in the domestic coal industry, the electric power generation industry, the domestic steel industry or in general economic conditions. In addition to the assumptions above, the financial and operating assumptions include: - Our coal royalty revenues, including overriding royalty revenues, will increase to $52.3 million for the 12 months ending June 30, 2003 from $43.3 million for the year ended December 31, 2001, an increase of $9.0 million, or 21%, due to a 7% increase in coal production, from 29.0 million tons to 30.9 million tons. This does not include additional cash we expect to receive related to minimum royalty payments (net of recoupments). The increase in production will occur on our Appalachia properties and will be partially offset by a decrease on our Northern Powder River Basin properties. Production on our Illinois Basin properties will remain approximately the same. Coal prices received by our lessees will be marginally higher than prices received in late 2001. - Production at our Appalachia properties will increase to 24.5 million tons for the 12 months ending June 30, 2003 from 19.6 million tons for the year ended December 31, 2001, an increase of 4.9 million tons, or 25%, for the following principal reasons: - Production from the Eunice property will increase 0.6 million tons, from 1.8 million tons for the year ended December 31, 2001 to 2.4 million tons for the 12 months ending June 30, 2003, or 33%, as a longwall mining operation moves onto and off of our property from an adjacent property in 2002. This increase follows a 1.3 million ton decrease from 2000 to 2001 due primarily to the closure of another longwall mine as a result of adverse geologic conditions and a portion of the surface mining being performed on an adjacent property during 2001. - Production from our West Fork property will increase 2.5 million tons, from 0.2 million tons for the year ended December 31, 2001 to 2.7 million tons for the 12 months ending June 30, 2003, as our lessee moved its longwall mining operations onto our property from an adjacent property in mid-2002. - Production from our Welch/Wyoming property will increase 464,000 tons, from 221,000 tons for the year ended December 31, 2001 to 685,000 tons for the 12 months ending June 30, 44 2003, primarily because the 12 months ending June 30, 2003 will reflect a full year's operations of a new continuous miner that began operating in mid-2001. - Production from our Kingston property will increase 589,000 tons, from 740,000 tons for the year ended December 31, 2001 to 1,329,000 tons for the 12 months ending June 30, 2003, or 80%, as a continuous mining operation that had been on an adjacent property during 2001 moved back onto our property in mid-2002. In addition, our lessee opened a new underground mine in early 2002. - Our Sincell property, which had no production in 2001, will produce 218,000 tons in the 12 months ending June 30, 2003, as our lessee's operations move onto our property from an adjacent property in early 2003. - Production from our Lynch property will increase 0.5 million tons, from 3.1 million tons for the year ended December 31, 2001 to 3.6 million tons for the 12 months ending June 30, 2003, or 16%, due to an underground mine reaching full production in late 2002 and the commencement of operations of a new surface mine in early 2003. - Production at our Northern Powder River Basin properties will decline 2.9 million tons, from 6.7 million tons for the year ended December 31, 2001 to 3.8 million tons for the 12 months ending June 30, 2003, or 42%. This decrease is the result of the typical variations that can result from our checkerboard ownership pattern on our properties in this area. - Other income, excluding overriding royalty revenues, will decrease $0.4 million, from $1.1 million for the year ended December 31, 2001 to $0.7 million for the 12 months ending June 30, 2003, because other income for 2001 included the recognition of transportation fees from a lessee that had been previously unreported by the lessee for several years. - General and administrative expenses will be $4.4 million for the 12 months ending June 30, 2003 and will consist of general and administrative expenses of approximately $2.9 million per year related to the WPP Group and Arch Coal Contributed Properties and annual costs of approximately $1.5 million that we expect to incur as a result of becoming a publicly traded partnership. These latter expenses include costs associated with tax return preparation, accounting support fees, annual and quarterly reports to unitholders, investor relations and registrar and transfer agent fees. - We will have no interest expense as we do not anticipate having any outstanding borrowings during the year ending June 30, 2003. We will, however, incur a commitment fee of $0.5 million on our bank credit facility. - We will incur less than $100,000 in capital expenditures, consistent with our assumption that we will not make any acquisitions during this period. If we do make any acquisitions, we will fund them with borrowings under our credit facility and proceeds from the issuance of our common units. A portion of any such capital expenditures may be maintenance capital expenditures, which will be deducted from our pro forma operating surplus for the period. While we believe that these assumptions are reasonable in light of management's current beliefs concerning future events, the assumptions underlying the projections are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash from operating surplus that we generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all units, in which event the market price of the common units may decline materially. Consequently, the statement that we believe that we will have sufficient available cash from operating surplus to pay the full minimum quarterly distribution on all units for each quarter through June 30, 2003 should not be regarded as a representation by us or the underwriters or any other person that we will make such a distribution. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading "Risk Factors" and elsewhere in this prospectus. 45 SELECTED HISTORICAL FINANCIAL AND OPERATING DATA The following tables show selected historical financial and operating data for Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and the Arch Coal Contributed Properties, in each case for the periods and as of the dates indicated. We derived the selected historical financial data for the WPP Group as of and for the years ended December 31, 1997, 1998, 1999, 2000 and 2001 from the audited financial statements of the WPP Group, and we derived the selected historical financial data for the Arch Coal Contributed Properties as of and for the years ended December 31, 1999, 2000 and 2001 from the audited financial statements of the Arch Coal Contributed Properties. We derived the selected historical financial data for the Arch Coal Contributed Properties as of and for the years ended December 31, 1997 and 1998 from the accounting records of Arch Coal. We derived the selected historical financial data for the WPP Group and the Arch Coal Contributed Properties for the six months ended June 30, 2001 and 2002 from the unaudited financial statements of the WPP Group and the Arch Coal Contributed Properties. In the opinion of these entities, the unaudited financial statements have been prepared on the same basis as the audited financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. We derived the information in the following tables from, and that information should be read together with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included elsewhere in this prospectus. The tables should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations." While substantially all of the producing coal-related assets and operations of the WPP Group are being contributed to us, some assets and liabilities are being retained by the WPP Group. 46 WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP (IN THOUSANDS, EXCEPT PRICE DATA)

SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------------------------------ ------------------ 1997 1998 1999 2000 2001 2001 2002 -------- -------- -------- -------- -------- ------- -------- (UNAUDITED) INCOME STATEMENT DATA: REVENUES: Coal royalties...................... $ 15,475 $ 20,412 $ 15,754 $ 11,585 $ 15,458 $ 6,946 $ 10,313 Timber royalties.................... 3,475 3,738 3,770 4,236 3,691 3,449 1,618 Gain on sale of property............ 75 70 205 3,982(a) 3,125(a) 51 85 Property taxes...................... 1,264 1,538 1,163 1,404 1,184 575 638 Other............................... 1,175 1,416 1,293 1,342 2,512 815 745 -------- -------- -------- -------- -------- ------- -------- Total revenues...................... 21,464 27,174 22,185 22,549 25,970 11,836 13,399 EXPENSES: General and administrative.......... 2,977 3,092 3,161 3,009 2,981 1,478 1,549 Taxes other than income............. 1,596 1,858 1,447 1,701 1,457 721 782 Depreciation, depletion and amortization...................... 1,708 1,996 1,270 1,168 1,369 933 1,477 -------- -------- -------- -------- -------- ------- -------- Total expenses...................... 6,281 6,946 5,878 5,878 5,807 3,132 3,808 -------- -------- -------- -------- -------- ------- -------- Income from operations................ 15,183 20,228 16,307 16,671 20,163 8,704 9,591 Other income (expense): Interest expense.................... (4,894) (5,505) (4,353) (4,167) (3,966) (2,009) (2,929) Interest income..................... 225 292 254 321 270 170 73 Reversionary interest............... -- -- -- -- (1,924)(b) -- (561)(b) -------- -------- -------- -------- -------- ------- -------- Net income............................ $ 10,514 $ 15,015 $ 12,208 $ 12,825 $ 14,543 $ 6,865 $ 6,174 ======== ======== ======== ======== ======== ======= ======== BALANCE SHEET DATA (AT PERIOD END): Total assets.......................... $ 79,521 $ 78,297 $ 76,089 $ 76,510 $ 88,224 $76,396 $126,446 Deferred revenue...................... 8,512 7,191 7,301 7,468 7,916 8,314 8,537 Long-term debt........................ 33,048 55,979 53,431 50,681 47,716 49,227 91,146 (b) Total liabilities..................... 50,017 66,378 64,038 61,584 68,055 61,256 103,603 Partners' capital..................... 29,504 11,919 12,051 14,926 20,169 15,140 22,843 CASH FLOW DATA: Net cash flow provided by (used in): Operating activities................ $ 12,186 $ 16,210 $ 13,838 $ 10,670 $ 13,056 $ 8,480 $ 5,892 Investing activities................ 48 (46) 188 3,976 2,685 22 (42,885) Financing activities................ (12,607) (15,472) (14,645) (14,630) (15,434) (8,059) 39,724 OTHER DATA: Royalty coal tons produced by lessees............................. 8,681 10,568 9,799 7,422 10,309 4,922 5,724 Average gross coal royalty per ton.... $ 1.78 $ 1.93 $ 1.61 $ 1.56 $ 1.50 $ 1.41 $ 1.80 OTHER FINANCIAL DATA: Capital expenditures.................. 48 109 23 25 8,974(b) 29 35,123 (b)

--------------- (a) Western Pocahontas Properties Limited Partnership sold surface land at a gain of $4.0 million and $3.1 million in 2000 and 2001, respectively. (b) The previous owner of Western Pocahontas Properties Limited Partnership's coal and timber properties retained a reversionary interest in those properties whereby it received either a 25% or 28% interest in the net revenues of the properties after July 1, 2001. Western Pocahontas Properties Limited Partnership accrued approximately $1.9 million related to the reversionary interest in 2001 and $561,000 in the six months ended June 30, 2002. In December 2001, Western Pocahontas Properties Limited Partnership purchased the reversionary interest related to its Kentucky properties for approximately $8.9 million. In March 2002, Western Pocahontas Properties Limited Partnership purchased the remaining portion of the reversionary interest for approximately $35.1 million. These purchases were financed with a $45 million loan. 47 GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP (IN THOUSANDS, EXCEPT PRICE DATA)

SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------------------------- ----------------- 1997 1998 1999 2000 2001 2001 2002 ------- ------- ------- ------- ------- ------- ------- (UNAUDITED) INCOME STATEMENT DATA: REVENUES: Coal royalties................................ $ 7,421 $ 8,684 $11,688 $ 7,966 $ 7,457 $ 3,219 $ 3,442 Lease and easement income..................... 568 490 480 583 787 156 234 Gain on sale of property...................... 1,845 930 12 709 439 439 -- Property taxes................................ 89 82 81 87 88 33 31 Other......................................... 120 101 73 45 31 145 193 ------- ------- ------- ------- ------- ------- ------- Total revenues................................ 10,043 10,287 12,334 9,390 8,802 3,992 3,900 EXPENSES: General and administrative.................... 698 488 574 481 611 234 273 Taxes other than income....................... 104 100 98 107 110 42 44 Depreciation, depletion and amortization...... 1,971 2,178 2,725 2,244 2,144 1,078 1,203 ------- ------- ------- ------- ------- ------- ------- Total expenses................................ 2,773 2,766 3,397 2,832 2,865 1,354 1,520 ------- ------- ------- ------- ------- ------- ------- Income from operations.......................... 7,270 7,521 8,937 6,558 5,937 2,638 2,380 Other income (expense): Interest expense.............................. (6,153) (5,450) (4,999) (4,657) (3,652) (2,080) (1,141) Interest income............................... 201 30 63 376 307 172 65 ------- ------- ------- ------- ------- ------- ------- Net income before extraordinary item............ 1,318 2,101 4,001 2,277 2,592 730 1,304 Loss on early extinguishment of debt.......... -- -- (2,678)(a) -- -- -- -- ------- ------- ------- ------- ------- ------- ------- Net income...................................... $ 1,318 $ 2,101 $ 1,323 $ 2,277 $ 2,592 $ 730 $ 1,304 ======= ======= ======= ======= ======= ======= ======= BALANCE SHEET DATA (AT PERIOD END): Total assets.................................... $69,177 $68,148 $69,616 $70,514 $70,236 $69,924 $70,361 Deferred revenue................................ 1,368 1,783 1,207 1,297 1,034 1,644 1,324 Long-term debt.................................. 54,391 51,115 50,125 48,625 47,125 47,875 46,375 Total liabilities............................... 62,492 59,362 53,508 52,129 50,110 51,660 49,592 Partners' capital............................... 6,685 8,786 16,108(a) 18,385 20,126 18,264 20,769 CASH FLOW DATA: Net cash flow provided by (used in): Operating activities.......................... $ 54 $ 3,522 $ 3,150 $ 5,731 $ 3,677 $ 2,491 $ 2,701 Investing activities.......................... 4,029 1,102 2 726 475 475 -- Financing activities.......................... (4,416) (3,984) (3,136) (6,205) (4,564) (3,072) (2,473) OTHER DATA: Royalty coal tons produced by lessees........... 8,896 9,744 11,746 9,172 8,509 4,607 3,590 Average gross coal royalty per ton.............. $ 0.83 $ 0.89 $ 1.00 $ 0.87 $ 0.88 $ 0.70 $ 0.96 OTHER FINANCIAL DATA: Capital expenditures............................ -- -- -- -- -- -- --

--------------- (a) Great Northern Properties Limited Partnership paid a prepayment penalty and expensed deferred financing costs related to the retirement of $57.0 million of debt in 1999. These expenses were classified as an extraordinary loss on the early extinguishment of debt. Simultaneously with the debt extinguishment, Great Northern Properties Limited Partnership borrowed $52.0 million and the partners contributed $6.0 million to the partnership. 48 NEW GAULEY COAL CORPORATION (IN THOUSANDS, EXCEPT PRICE DATA)

SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------------------------- --------------- 1997 1998 1999 2000 2001 2001 2002 ------- ------- ------- ------ ------- ------ ------ (UNAUDITED) INCOME STATEMENT DATA: REVENUES: Coal royalties................................. $ 327 $ 1,429 $ 1,332 $ 955 $ 1,609 $ 776 $ 938 Gain on sale of property....................... -- -- -- -- 25 -- -- Property taxes................................. 10 23 26 25 28 -- -- Other.......................................... 4 65 75 32 61 83 52 ------- ------- ------- ------ ------- ------ ------ Total revenues................................. 341 1,517 1,433 1,012 1,723 859 990 EXPENSES: General and administrative..................... 17 30 27 32 41 20 59 Taxes other than income........................ 55 62 54 48 45 11 11 Depreciation, depletion and amortization....... 34 160 214 132 212 106 79 ------- ------- ------- ------ ------- ------ ------ Total expenses................................. 106 252 295 212 298 137 149 ------- ------- ------- ------ ------- ------ ------ Income from operations........................... 235 1,265 1,138 800 1,425 722 841 Other income (expense): Interest expense............................... (270) (175) (145) (139) (132) (66) (64) Interest income................................ 26 6 -- -- 15 -- 15 Reversionary interest.......................... -- -- -- -- (85)(a) -- (34)(a) ------- ------- ------- ------ ------- ------ ------ Net income....................................... $ (9) $ 1,096 $ 993 $ 661 $ 1,223 $ 656 $ 758 ======= ======= ======= ====== ======= ====== ====== BALANCE SHEET DATA (AT PERIOD END): Total assets..................................... $ 4,599 $ 4,925 $ 4,636 $4,553 $ 4,625 $4,652 $4,591 Deferred revenue................................. 4,589 4,189 3,902 3,747 3,601 3,625 3,323 Long-term debt................................... 1,964 1,866 1,781 1,682 1,584 1,634 1,531 Total liabilities................................ 6,438 6,169 5,787 5,542 5,391 5,386 4,999 Stockholders' deficit............................ (1,839) (1,244) (1,151) (989) (766) (734) (408) CASH FLOW DATA: Net cash flow provided by (used in): Operating activities........................... $ 316 $ 600 $ 900 $ 604 $ 1,323 $ 434 $ 475 Investing activities........................... (21) -- (67) -- (175) -- -- Financing activities........................... (505) (370) (979) (591) (1,091) (445) (449) OTHER DATA: Royalty coal tons produced by lessees............ 118 522 572 356 718 372 311 Average gross coal royalty per ton............... $ 2.77 $ 2.74 $ 2.33 $ 2.68 $ 2.24 $ 2.09 $ 3.02 OTHER FINANCIAL DATA: Capital expenditures............................. 21 -- 67 -- -- -- --

--------------- (a) The previous owner of New Gauley Coal's Corporation's Alabama property retained a 25% interest in the net revenue of the property after July 1, 2001. New Gauley Coal Corporation accrued approximately $85,000 related to the reversionary interest in 2001 and $34,000 related to the first six months of 2002. 49 ARCH COAL CONTRIBUTED PROPERTIES (IN THOUSANDS, EXCEPT PRICE DATA)

SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------------------------------------- ----------------- 1997 1998 1999 2000 2001 2001 2002 ----------- ----------- -------- ------- ------- ------- ------- (UNAUDITED) (UNAUDITED) (UNAUDITED) INCOME STATEMENT DATA: REVENUES: Coal royalties.......................... $ 9,306 $ 11,379 $ 13,193 $16,152 $18,415 $ 9,331 $ 8,880 Other royalties......................... 971 954 983 907 1,363 730 925 Property taxes.......................... 975 1,239 1,173 1,204 1,033 516 538 -------- -------- -------- ------- ------- ------- ------- Total revenues.......................... 11,252 13,572 15,349 18,263 20,811 10,577 10,343 DIRECT COSTS AND EXPENSES: Depletion............................... 3,095 4,769 5,625 5,395 6,382 3,225 2,969 Property taxes.......................... 975 1,239 1,173 1,204 1,033 516 538 Other expense........................... -- -- -- 18 283 147 411 Write-down of impaired assets........... -- -- 65,229(a) -- -- -- -- -------- -------- -------- ------- ------- ------- ------- Total expenses.......................... 4,070 6,008 72,027 6,617 7,698 3,888 3,918 -------- -------- -------- ------- ------- ------- ------- Excess (deficit) of revenues over direct costs and expenses...................... $ 7,182 $ 7,564 $(56,678) $11,646 $13,113 $ 6,689 $ 6,425 ======== ======== ======== ======= ======= ======= ======= BALANCE SHEET DATA (AT PERIOD END): Total assets.............................. $112,562 $107,932 $102,168 $97,230 $90,733 $93,587 $87,744 Deferred revenue.......................... 7,857 8,971 10,078 10,035 10,409 9,823 9,823 Total liabilities......................... 8,583 9,897 10,937 10,954 11,180 10,404 10,373 Net assets purchased...................... 103,979 98,035 91,231 86,276 79,553 83,183 77,371 CASH FLOW DATA: Direct cash flow from contributed properties.............................. (b) $ 13,508 $ 15,355 $16,601 $19,836 $ 9,782 $ 8,607 OTHER DATA: Royalty coal tons produced by lessees..... 4,634 6,565 7,702 9,862 11,281 5,750 5,317 Average gross coal royalty per ton........ $ 2.01 $ 1.73 $ 1.71 $ 1.64 $ 1.63 $ 1.62 $ 1.67 OTHER FINANCIAL DATA: Capital Expenditures...................... -- -- -- -- -- -- --

--------------- (a) During 1999, pursuant to SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," the carrying value of certain coal reserves was written down to fair value resulting in a non-cash impairment charge of $65.2 million. (b) Cash flow information for 1997 is not available. 50 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 and pro forma financial statements and notes thereto included elsewhere in this prospectus. For more detailed information regarding the basis of presentation for the following financial information, see the notes to the historical and pro forma financial statements. After the Introduction, there is a separate section for each of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and for the Arch Coal Contributed Properties. The Arch Coal Contributed Properties include the properties contributed to us by Ark Land Company, a subsidiary of Arch Coal, Inc. This discussion includes certain forward-looking statements. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, we urge you to review the risk factors set forth in "Risk Factors" beginning on page 14. These and other risks could cause our actual results to differ materially from those contained in any forward-looking statement. Please read "Forward Looking Statements." INTRODUCTION We are a limited partnership recently formed by the WPP Group, the largest owner of coal reserves in the United States other than the U.S. government, and Arch Coal, Inc., the second largest U.S. coal producer. We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2001, we controlled approximately 1.15 billion tons of proven and probable coal reserves in eight states. In 2001, our lessees produced 29 million tons of coal from our properties and our total revenues were $47.2 million on a pro forma basis, including coal royalty revenues of $42.4 million. We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. Our royalty payments are based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, subject to a minimum payment. As of September 1, 2002, our reserves were located on 45 separate properties and are subject to 62 leases with 31 lessees. In 2001, approximately 57% of the coal produced from our properties came from underground mines and 43% came from surface mines. As of December 31, 2001, approximately 65% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which meets the standards imposed by the Clean Air Act and constitutes approximately 25% of our reserves. Coal produced from our properties is burned in electric power plants located east of the Mississippi River and in Montana and Minnesota. Approximately 12% of our lessees' 2001 coal production was metallurgical coal, which our lessees sold to steel companies in the Eastern United States, South America, Europe and Asia. The WPP Group retained coal reserve properties that are leased to third parties but that are short-lived, that are subject to leases that contain uneconomic terms or that are experiencing permitting problems. The WPP Group has retained other unleased coal reserve properties, surface lands and timberlands that generated approximately $5.7 million, $10.5 million, and $9.9 million of revenue for 1999, 2000 and 2001, respectively. The historical financial statements and related discussions that follow for the members of the WPP Group include results of operations related to these retained properties. The historical financial statements for the WPP Group do not reflect the historical results that would have been obtained if only the contributed properties had been presented. The Arch Coal Contributed Properties historical financial statements include only properties that are being contributed to us. The Arch Coal Contributed Properties is not a legal entity and, except for revenues earned from the properties and certain direct costs and expenses of the properties, no separate financial information was maintained or is presented. 51 During the last few years, steam coal prices have varied greatly. At the beginning of 2000, demand for steam coal was depressed due to excessive stockpiling of coal by utilities in anticipation of "Y2K" problems. By late summer of 2000, these stockpiles returned to normal levels, utilities reentered the market to buy coal and sufficient supply was not available to meet demand. These events contributed to a rapid increase in coal prices during late 2000. These higher spot prices prevailed for most of 2001. In late 2001, prices began to decline as demand for coal fell due to unusually warm weather during the winter of 2001-2002 and the sluggish U.S. economy. The effect of these lower spot prices on our results of operations for the near future should be limited because our lessees will receive previously contracted prices for much of their production. The prices have stabilized at recent historical levels during 2002. During 2001, approximately 14% of our coal royalty revenues were from metallurgical coal. Prices of metallurgical coal have remained relatively stable in the past two years. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. Metallurgical coal production has gradually decreased during the past few years due to a decline in exports as a result of the strength of the U.S. dollar and increasing use of electric arc furnaces and pulverized coal, rather than metallurgical coal, for steel production. Metallurgical coal can also be used as steam coal. However, some metallurgical coal mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal due to its higher price. If they are unable to sell metallurgical coal, these mines may not be economically viable and may close. In addition to coal royalty revenue, we will generate nominal revenue from the royalty on oil and gas and coalbed methane leases, an overriding royalty arrangement and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property. We will not have any timber revenues in the future because the WPP Group has retained all of the timber on our properties and the Arch Coal Contributed Properties does not include any timber assets. Most lessees are required to reimburse us for property taxes we pay on the leased property. These property tax reimbursements are shown as revenue on the historical financial statements included in this prospectus. The corresponding property tax expenses are included as "taxes other than income." The WPP Group's property tax expenses are higher than its property tax revenue because the WPP Group is retaining certain properties and because some of the properties contributed by the WPP Group are unleased and, therefore, no reimbursements are received. General and administrative expenses include salary and benefits, rent, expenses and other costs related to managing the properties. An affiliate charges the WPP Group for certain finance, tax, treasury and insurance expenses. The Arch Coal Contributed Properties do not maintain stand-alone corporate treasury, legal, tax, human resources, general administration or other similar corporate support functions. Corporate general and administrative expenses have not been previously allocated to the Arch Coal Contributed Properties because there was not sufficient information to develop a reasonable cost allocation. In the future, we will reimburse our general partner and its affiliates for direct and indirect expenses they incur on our behalf, including general and administrative expenses. Depreciation, depletion and amortization consists primarily of depletion on the coal properties. Depletion of coal reserve properties is calculated on a unit-of-production basis and thus closely correlates to the amount of coal production and coal royalty revenue for the period. RESULTS OF OPERATIONS WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP Six months ended June 30, 2002 compared with six months ended June 30, 2001 Revenues: Combined revenues for the six months ended June 30, 2002 were $13.4 million compared to $11.8 million for the six months ended June 30, 2001, an increase of $1.6 million, or 14%. Coal royalty revenues for the six months ended June 30, 2002 were $10.3 million compared to $6.9 million for the six months ended June 30, 2001, an increase of $3.4 million, or 49%. Over these same 52 periods, production increased by 801,000 tons, or 16%, from 4.9 million tons to 5.7 million tons. The increases in production and coal royalties were primarily due to: - Eastern Kentucky: Production from the Evans-Laviers property increased 64,000 tons from 1,527,000 tons to 1,591,000 tons, which resulted in increased revenues of $254,000. This increase was due to the addition of another section to an underground mine. On the Chesapeake Minerals property, production increased by 57,000 tons for the six months ended June 30, 2002, resulting in a royalty revenue increase of $175,000. This increase was due to a reopening of a mine after the purchase of the mine by a new owner. - Southern West Virginia: Production from the Eunice property increased by 267,000 tons from 1,046,000 tons to 1,313,000 tons, resulting in increased royalty revenues of $931,000. This increase was due to a longwall mining operation moving back onto the property and also to a higher sales price for the coal. Additionally, on the West Fork property, production increased by 690,000 tons from the six months ended June 30, 2001, resulting in increased royalty revenues of $1,610,000. This increase was the result of a longwall mine moving onto the property. Also, on the Welch/Wyoming property, production increased by 258,000 tons from the six months ended June 30, 2001, resulting in increased royalty revenue of $739,000. This increase was due to a new mine opening on the property. These increases were partially offset by a decrease in production at the Rockhouse Fork property of 211,000 tons, which led to a royalty revenue reduction of $545,000. This reduction was due to lower than expected production by the contract miner. - Northern Appalachia: Production from the Beaver Creek property increased by 292,000 tons from 24,000 tons to 316,000 tons, resulting in increased royalty revenue of $650,000. This increase was due to production moving back onto the property. - Indiana: Production from the Hocking-Wolford/Cummings property decreased by 438,000 tons from 864,000 tons to 426,000 tons, resulting in a decrease in royalty revenue of $515,000. This decrease was due to a shift in mining to adjacent non-owned properties. Timber revenues decreased by $1.8 million from $3.4 million for the six months ended June 30, 2001 to $1.6 million for the six months ended June 30, 2002. This decrease was due to a greater than normal harvest for the six months ended June 30, 2001 and a smaller than normal harvest for the six months ended June 30, 2002 due to reduced demand for timber. Expenses: Aggregate expenses for the six months ended June 30, 2002 were $3.8 million compared to $3.1 million for the six months ended June 30, 2001, an increase of $700,000, or 23%. This increase was primarily due to increased depletion due to increased production. Other Income (Expense): Interest expense was $2.9 million for the six months ended June 30, 2002 compared to $2.0 million for the six months ended June 30, 2001. This increase was due to increased debt arising from the acquisition of the CSX reversionary interest in December 2001 and March 2002. Other expense included $561,000 related to the reversionary interest for the six months ended June 30, 2002. Net Income: Net income was $6.2 million for the six months ended June 30, 2002 compared to $6.9 million for the six months ended June 30, 2001, a decrease of $700,000, or 10%. This decrease was primarily due to increased operating and interest expenses and the purchase of the CSX reversionary interest, partially offset by increases revenues. Year ended December 31, 2001 compared with year ended December 31, 2000 Revenues: Combined revenues in 2001 were $26.0 million compared to $22.5 million in 2000, an increase of $3.5 million, or 15%. 53 Coal royalty revenues in 2001 were $15.5 million compared to $11.6 million in 2000, an increase of $3.9 million, or 33%. Over these same periods, production increased by 2.9 million tons, or 39%, from 7.4 million tons to 10.3 million tons. The increases in production and coal royalties were primarily due to: - Eastern Kentucky: Production from the Evans-Laviers property increased 2.6 million tons, from 1.2 million tons to 3.8 million tons, which resulted in increased royalty revenues of $3.8 million. This increase was primarily due to the opening of a new deep mine late in 2000, a large underground mine reaching full production in 2001 and the reopening of a temporarily idled surface and highwall mine in July 2001 at a higher royalty rate. On the Chesapeake Mineral property, production increased by 218,000 tons in 2001 due to the reopening of the mine under new ownership. This was partially offset by the reduction of production at another lease on this property. This resulted in a royalty revenue increase of $269,000. - Southern West Virginia: Production from the Eunice property decreased by 1.3 million tons, from 3.1 million tons to 1.8 million tons, resulting in a decrease in royalty revenues of $1.1 million. This decrease was due primarily to the closure of a longwall mine as a result of adverse geologic conditions and surface mining being performed on adjacent property during the year. This decrease in production was partially offset by an increase in production from the Dorothy-Sarita property of 301,000 tons, from 351,000 tons to 652,000 tons, that resulted in increased royalty revenues of $400,000. This increase in production was due to the addition of a surface and highwall mine. On the Rockhouse Fork property, production decreased by 148,000 tons, from 470,000 tons to 322,000 tons, that reduced royalty revenues by $348,000. This decrease in production was due to a decision to mine in a thinner part of the coal seam, geologic conditions and a change in contractors by the lessee. Timber revenues decreased to $3.7 million in 2001 from $4.2 million in 2000, a decrease of $0.5 million, or 13%. The decrease was due to a one-time sale of timber in 2000 for $700,000 on a parcel in Northern Appalachia, which contained 1.5 million board feet of timber. Gain on sale of property was $3.1 million in 2001 and $4.0 million in 2000. These gains were related to the sale of 1,928 and 1,391 acres of land in 2001 and 2000, respectively. Other revenues increased to $2.5 million in 2001 from $1.3 million in 2000, an increase of $1.2 million, or 92%. This increase was due to a determination that a lessee was required to pay transportation fees that were previously unreported by the lessee for several years. Expenses: Aggregate expenses for 2001 were $5.8 million compared to $5.9 million for 2000, a decrease of $0.1 million or 1%, primarily due to a decrease in property taxes that was partially offset by increased depletion attributed to higher coal production. Other Income (Expense): Interest expense was $4.0 million for 2001 compared to $4.2 million for 2000, a decrease of $0.2 million, or 5%. This decrease was due to scheduled principal reductions. Reversionary Interest: The previous owner of Western Pocahontas Properties Limited Partnership's coal and timber properties (CSX Corporation and certain of its affiliates) retained a reversionary interest in those properties whereby it received either a 25% or 28% interest in the properties and the net revenues of the properties after July 1, 2001, and in the net proceeds of any property sale occurring prior to July 1, 2001. In 2001, we accrued $1.9 million related to the reversionary interest. Net Income: Net income was $14.5 million in 2001 compared to $12.8 million in 2000, an increase of $1.7 million or 13%. This increase was primarily due to increased coal production by our lessees and correspondingly higher royalty payments. Year ended December 31, 2000 compared with year ended December 31, 1999 Revenues: Combined revenues in 2000 were $22.5 million compared to $22.2 million in 1999, an increase of $0.3 million, or 2%. 54 Coal royalty revenues in 2000 were $11.6 million compared to $15.8 million in 1999, a decrease of $4.2 million, or 26%. Over these same periods, production decreased by 2.4 million tons, or 24%, from 9.8 million tons to 7.4 million tons. The decreases in production and coal royalties were primarily due to: - Eastern Kentucky: Production from the Evans-Laviers property decreased 0.6 million tons, from 1.8 million tons to 1.2 million tons, which resulted in decreased royalty revenue of $0.8 million. The decrease resulted primarily from a sublessee losing a major sales contract in February 2000 and a resulting decision to temporarily idle the mine. - Southern West Virginia: Production from the Dorothy-Sarita property decreased by 564,000 tons, from 915,000 tons to 351,000 tons, which resulted in decreased royalty revenue of $747,000. The decrease resulted primarily from the closing of a deep mine due to exhaustion of reserves in the seam being mined. This decrease in production was partially offset by an increase in certain royalty rates. On the Eunice property, production was nearly constant but royalty revenue decreased $465,000 because of a decrease in the sales price of the coal and a shift in production to mining methods that yielded a lower royalty rate. On the Y&O property, production decreased 515,000 tons, from 1,249,000 tons to 734,000 tons, which resulted in decreased royalty revenue of $1.4 million. This decrease was primarily due to the lessee's longwall mine ceasing operations in early 2000 upon exhaustion of reserves in the seam being mined and was partially offset by production increases at two other leases on this property. On the Rockhouse Fork property, production decreased 100,000 tons from 570,000 tons to 470,000 tons, which resulted in a royalty revenue decrease of $228,000. This decrease was due to the a thinning coal seam and other adverse geologic conditions. Timber revenues increased to $4.2 million in 2000 from $3.8 million in 1999, an increase of $0.4 million, or 12%. This increase was primarily attributable to higher rates under a renegotiated contract starting in January 2000 with our principal timber operator in Southern West Virginia. Gain on sale of property was $4.0 million in 2000 and $0.2 million in 1999. The gain in 2000 was the result of the sale of 1,391 acres of surface land. Other Income (Expense): Interest expense was $4.2 million for 2000 compared to $4.4 million for 1999, a decrease of $0.2 million, or 4%, resulting from principal reductions. Net Income: Net income was $12.8 million for 2000 compared to $12.2 million for 1999, an increase of $0.6 million, or 5%. This increase primarily resulted from a gain on sale of property and was partially offset by decreased coal royalty payments. GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP Six months ended June 30, 2002 compared with six months ended June 30, 2001 Revenues: Combined revenues for the six months ended June 30, 2002 were $3.9 million compared to $4.0 million for the six months ended June 30, 2001, a decrease of $0.1 million. Coal royalty revenues for the six months ended June 30, 2002 were $3.4 million compared to $3.2 million for the six months ended June 30, 2001, an increase of $0.2 million, or 6%. Over these periods, production decreased by 1.0 million tons, from 4.6 million tons to 3.6 million tons, or 22%. The increase in coal royalty revenues and the decrease in production were primarily due to: - Production from the Washington state property, which is not being contributed to us, increased by 0.4 million, which resulted in increased royalty of $0.7 million due to production moving onto the property. Production from the Big Sky property increased by 0.1 million, which resulted in increased coal royalty revenues of $0.2 million, while production from the Western Energy property decreased 1.2 million tons from 2.6 million tons to 1.4 million tons, which resulted in decreased coal royalty revenues of $0.6 million. The production variances on the Big Sky and Western Energy properties were the result of the typical variations that can result from the checkerboard ownership 55 pattern in these mines. This ownership pattern causes mining operations to periodically move onto the property from contiguous non-owned property and back off again. Other Income (Expense): Interest expense for the six months ended June 30, 2002 was $1.1 million compared to $2.1 million for the six months ended June 30, 2001, a decrease of $1.0 million, or 48%. This was due to a decrease in interest rates from an average of 8.36% for the six months ended June 30, 2001 to 4.6% for the six months ended June 30, 2002. Net Income: Net income was $1.3 million for the six months ended June 30, 2002 compared to $700,000 for the six months ended June 30, 2001, an increase of $600,000, or 86%. This increase primarily resulted from a reduction in interest expense. Year ended December 31, 2001 compared with year ended December 31, 2000 Revenues: Combined revenues in 2001 were $8.8 million compared to $9.4 million in 2000, a decrease of $0.6 million, or 6%. Coal royalty revenues in 2001 were $7.5 million compared to $8.0 million in 2000, a decrease of $0.5 million, or 6%. Over these periods, production decreased by 663,000 tons, or 7%, from 9.2 million tons to 8.5 million tons. These decreases in production and coal royalties were primarily due to: - Production from the Western Energy property decreased by 783,000 tons, from 5.7 million tons to 4.9 million tons, which resulted in decreased royalty revenues of $1.1 million. This decrease in production was the result of the typical variations which can result from the checkerboard ownership pattern in this mine. This ownership pattern causes mining operations to periodically move from the property to contiguous non-owned property and back again. - Production from the Big Sky property increased by 0.4 million tons, from 1.4 million to 1.8 million tons, which resulted in increased royalty revenues of $0.4 million. These increases were due to the favorable location of mining operations relative to the checkerboard ownership pattern. Lease and easement income in 2001 was $787,000 compared to $583,000 in 2000. This increase was primarily attributable to surface use payments relating to increased mining on surface property owned by us. Gain on sale of property was $439,000 in 2001. Other Income (Expense): Interest expense was $3.7 million for 2001 compared to $4.7 million for 2000, a decrease of $1.0 million, or 21%. This decrease primarily resulted from a reduction in the outstanding principal balance of debt combined with a reduction in interest rates from an average of 9.3% in 2000 to 7.5% in 2001. Net Income: Net income was $2.6 million for 2001 compared to $2.3 million for 2000, an increase of $0.3 million, or 14%. This increase primarily resulted from a reduction in interest expense that was partially offset by lower coal royalties. Year ended December 31, 2000 compared with year ended December 31, 1999 Revenues: Combined revenues in 2000 were $9.4 million compared to $12.3 million in 1999, a decrease of $2.9 million, or 24%. Coal royalty revenues in 2000 were $8.0 million compared to $11.7 million in 1999, a decrease of $3.7 million, or 32%. Over these same periods, production decreased by 2.5 million tons, or 22%, from 11.7 million tons to 9.2 million tons. The decrease in production and coal royalties were primarily due to: - Production from the Western Energy property decreased in 2000 by 1.6 million tons, from 7.3 million tons to 5.7 million tons, and the contract price per ton decreased as a result of a price reopener provision, which resulted in decreased royalty revenues of $2.2 million. This decrease in 56 production was the result of the typical variations which can result from the checkerboard ownership pattern in the mine. - Production from the Big Sky property decreased in 2000 by 1.4 million tons, from 2.8 million tons to 1.4 million tons, which resulted in decreased royalty revenues of $1.4 million. This decrease in production was primarily due to the lessee losing a significant sales contract at the beginning of 2000. Gain on sale of property was $709,000 in 2000 resulting from the sale of surface land in Montana. Lease and easement income in 2000 was $583,000 compared to $480,000 in 1999. This increase was primarily attributable to surface use payments from increased mining on surface property owned by us. Expenses: Aggregate expenses for 2000 were $2.8 million compared to $3.4 million for 1999, a decrease of $0.6 million, or 17%. The decrease in expenses in 2000 primarily related to the decrease in depletion associated with the reduction in production during the period. Other Income (Expense): Interest expense was $4.7 million for 2000 compared to $5.0 million for 1999, a decrease of $0.3 million, or 6%. This increase was due to an increase in interest rates, which was partially offset by the reduction in the principal balance. Interest income increased to $376,000 for 2000 from $63,000 in 1999, due to cash placed in restricted accounts as required under the loan agreement. Extraordinary Item: In 1999, there was a one-time loss of $2.7 million relating to the early extinguishment of debt. Net Income: Net income was $2.3 million for 2000 compared to $1.3 million for 1999, an increase of $1.0 million, or 77%. This increase was primarily due to the extraordinary item in 1999, partially offset by lower coal revenues in 2000. NEW GAULEY COAL CORPORATION Six months ended June 30, 2002 compared with six months ended June 30, 2001 Revenues: Combined revenues for the six months ended June 30, 2002 were $990,000 compared to $859,000 for the six months ended June 30, 2001, an increase of $131,000, or 15%. Coal royalty revenues for the six months ended June 30,2002 were $938,000 compared to $776,000 for the six months ended June 30, 2001, an increase of $162,000, or 21%. Over the same period production decreased by 61,000 tons, or 16%, from 372,000 tons to 311,000 tons. This increase in coal royalties and the decrease in production were primarily due to: - Production on the Alabama property increased by 24,000 tons, which resulted in increased coal royalty revenues of $269,000, due partially to an increase in average sales. Of the coal royalty revenues, $140,000 was recognized as revenue due to increased recoupment. - Production on the West Virginia property decreased by 84,000 tons, which resulted in decreased coal royalty revenues of $123,000. Net Income: Net income was $758,000 for the six months ended June 30, 2002 compared to $656,000 for the six months ended June 30, 2001, an increase of $102,000, or 15%. This increase was primarily due to increased coal royalty revenues. Year ended December 31, 2001 compared with year ended December 31, 2000 Revenues: Combined revenues in 2001 were $1.7 million compared to $1.0 million in 2000, an increase of $0.7 million, or 70%. Coal royalty revenues in 2001 were $1.6 million compared to $1.0 million in 2000, an increase of $0.6 million, or 60%. Over these same periods, production increased by 362,000 57 tons, or 102%, from 356,000 tons to 718,000 tons. This increase in production and coal royalties was primarily due to: - Production from the West Virginia property increased by 292,000 tons, from 149,000 tons to 441,000 tons, which resulted in increased royalty revenues of $687,000. This increase resulted from the lessee's mining operations moving onto New Gauley Coal Corporation's property from adjacent reserves and an increase in the royalty rate. Expenses: Aggregate expenses for 2001 were $298,000 compared to $212,000 for 2000, an increase of $86,000, or 41%. This increase was due primarily to increased depletion associated with the increased production during the period. Net Income: Net income was $1.2 million for 2001 compared to $0.7 million for 2000, an increase of $0.5 million, or 71%. This increase was primarily due to increased coal royalty revenues. Year ended December 31, 2000 compared with year ended December 31, 1999 Revenues: Combined revenues in 2000 were $1.0 million compared to $1.4 million in 1999, a decrease of $0.4 million, or 29%. Coal royalty revenues in 2000 were $1.0 million compared to $1.3 million in 1999, a decrease of $0.3 million, or 23%. Over these same periods, production decreased by 216,000 tons, or 38%, from 572,000 tons to 356,000 tons. This decrease in production and coal royalties was primarily due to: - Production from the West Virginia property decreased by 100,000 tons, from 249,000 tons to 149,000 tons, which resulted in decreased royalty revenues of $70,000. This decrease was caused by the lessee moving its mining operations to adjacent reserves. - Production from the Alabama property decreased by 117,000 tons, from 323,000 tons to 206,000 tons, which resulted in decreased royalty revenues of $150,000. This decrease resulted from the lessee's decision to decrease sales and production due to depressed market prices. Expenses: Aggregate expenses for 2000 were $212,000 compared to $295,000 for 1999, a decrease of $83,000, or 28%. This decrease was primarily related to a decrease in depletion associated with reduced production during the period. Net Income: Net income was $661,000 for 2000 compared to $993,000 for 1999, a decrease of $332,000, or 33%. This decrease was primarily due to a reduction in coal royalties. ARCH COAL CONTRIBUTED PROPERTIES Six months ended June 30, 2002 compared with six months ended June 30, 2001 Revenues: Revenues for the six months ended June 30, 2002 were $10.3 million compared with $10.6 million for the six months ended June 30, 2001, a decrease of $0.3 million, or 3%. Coal royalty revenues for the six months ended June 30, 2002 were $8.9 million compared to $9.3 million for the six months ended June 30, 2001, a decrease of $0.4 million or 4%. Production decreased by 0.5 million tons, or 9%, from 5.8 million tons for the six months ended June 30, 2001 to 5.3 million tons for the six months ended June 30, 2002. The decrease in production and coal royalty revenues was primarily attributable to the following: - Southern West Virginia: Production from the Central Appalachia properties decreased 0.4 million tons, from 1.5 million tons for the six months ended June 30, 2001 to 1.1 million tons for the six months ended June 30, 2002, which resulted in decreased coal royalty revenues of $714,000. The decrease was primarily due to a reduction in production at the Campbell's Creek and Boone/ Lincoln properties. Production on the Campbell's Creek property decreased 148,000 tons to 546,000 tons and production on the Boone/Lincoln property decreased 262,000 tons to 110,000 tons, primarily as a result of a weaker coal demand. 58 Direct costs and expenses: Direct costs and expenses for each of the six months ended June 30, 2002 and 2001 were $3.9 million. Depletion decreased $0.3 million to $3.0 million for the six months ended June 30, 2002, primarily as a result of the reduced production during the period. This was offset by increased override royalties due to a third party. Those royalties increased $264,000 to $411,000 for the six months ended June 30, 2002 as a result of increased production on the property subject to the override. Year ended December 31, 2001 compared with year ended December 31, 2000 Revenues: Revenues in 2001 were $20.8 million compared with $18.3 million in 2000, an increase of $2.5 million, or 14%. Coal royalty revenues in 2001 were $18.4 million compared to $16.2 million in 2000, an increase of $2.2 million, or 14%. Production increased by 1.4 million tons, or 14%, from 9.9 million tons to 11.3 million tons. The increase in production and coal royalties were primarily attributable to the following: - Eastern Kentucky: Production from the Central Appalachia properties increased 1.2 million tons, from 6.2 million tons to 7.4 million tons, which resulted in increased coal royalty revenues of $2.0 million. This increase was due primarily to the ramp up of production at various surface and underground mines at the Lynch property that increased production from 2.0 million tons in 2000 to 3.1 million tons in 2001. Production at the Lone Mountain property also increased from 2.2 million tons in 2000 to 2.8 million tons in 2001 due to the installation of additional equipment at the lessee's mine. Other royalty revenues for 2001 were $1.4 million compared to $0.9 million in 2000, an increase of $0.5 million. Other royalty revenues are primarily attributable to override royalties associated with coal mined by lessees. Override royalties were $1.2 million in 2001 compared to $0.8 million in 2000. Direct costs and expenses: Direct costs and expenses in 2001 were $7.7 million compared to $6.6 million in 2000, an increase of $1.1 million, or 16%. This increase was largely due to increased depletion resulting from the increased production during the period. Depletion expense increased $1.0 million to $6.4 million in 2001 from $5.4 million in 2000. Year ended December 31, 2000 compared with year ended December 31, 1999 Revenues: Revenues in 2000 were $18.3 million compared to $15.3 million in 1999, an increase of $3.0 million, or 19%. Coal royalty revenues in 2000 were $16.2 million compared to $13.2 million in 1999, an increase of $3.0 million, or 22%. Production increased by 2.2 million tons, or 28%, from 7.7 million tons to 9.9 million tons. The increase in production and coal royalty revenues was primarily attributable to the following: - Eastern Kentucky: Production increased on the Central Appalachia properties by 2.3 million tons, from 3.9 million tons to 6.2 millions tons, which resulted in an increase in coal royalty revenues of $3.8 million. This increase was due primarily to the start up of production at various surface and underground mines at the Lynch property that increased production from 0.1 million tons in 1999 to 2.0 million tons in 2000. Direct Costs and Expenses: Direct costs and expenses in 2000 were $6.6 million compared to $72.0 million in 1999, a decrease of $65.4 million. This decrease is primarily due to a $65.2 million non-cash impairment charge on certain properties in 1999. During the fourth quarter of 1999, Arch Coal determined that, as a result of several adverse regulatory rulings and the continued negative pricing trends related to Central Appalachian coal production experienced by Arch Coal at that time, an evaluation of the recoverability of its active mining operations and coal reserves was necessary pursuant to SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The evaluation indicated that the future undiscounted cash flows of certain coal reserves were below the carrying value of such assets. Accordingly, Arch Coal adjusted the value of certain reserves. The estimated 59 fair value for the coal reserves with no future mine plans was based upon the fair value of these properties to be derived from subleased operations. The Arch Coal Contributed Properties affected by the write-down were written down to approximately $47.1 million, resulting in a non-cash impairment charge of $65.2 million. The impairment loss was recorded as a write-down of impaired assets in the statement of revenues and direct costs and expenses. Depletion expense decreased $0.2 million to $5.4 million in 2000 from $5.6 million in 1999. The decrease was a result of reduced depletion expense corresponding to the impairment charge. The impairment charge reduced the depletion rate on a per ton basis for 2000. The impact of the lower rates was partially offset by increased production in 2000. RELATED PARTY TRANSACTIONS For a description of our related party transactions, please read "Certain Relationships and Related Transactions." LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS AND CAPITAL EXPENDITURES Historically, each of the WPP Group and the Arch Coal Contributed Properties satisfied their working capital requirements and funded capital expenditures, other than property acquisitions, with cash generated from operations. Funds for property acquisitions have generally been obtained through borrowings. Following this offering, we believe that cash generated from operations and our borrowing capacity under our new credit facility will be sufficient to meet our working capital requirements and anticipated capital expenditures for the next several years. We anticipate that we will incur less than $100,000 in capital expenditures in the first year following the offering, consistent with our assumption that we will not make any acquisitions during this period. If we do make any acquisitions, we expect to fund them with borrowings under our credit facility and proceeds from the issuance of common units. A portion of our capital expenditures will be maintenance capital expenditures, which will be deducted from our pro forma operating surplus for the period. Our ability to satisfy any debt service obligations, to fund planned capital expenditures, to make acquisitions and to pay distributions to our unitholders will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control. For a more complete discussion of factors that will affect cash flow we generate from our operations, please read "Risk Factors." Our capital expenditures have historically been minimal. Please read "Cash Available for Distribution." Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as plant operating expenses as we incur them. Western Pocahontas Properties Limited Partnership Net cash provided by operations in the six months ended June 30, 2002 was $5.9 million compared to $8.5 million in the six months ended June 30, 2001, a decrease of $2.6 million. This decrease was partially due to a $1.8 million decrease in timber royalty. Reversionary interest payable decreased $900,000 as a result of the purchase of the reversionary interest from CSX. Net cash used in investing activities in the six months ended June 30, 2002 was $42.9 million compared to $22,000 in the six months ended June 30, 2001, an increase of $42.9 million. This increase primarily reflected the purchase of the reversionary interest from CSX in March 2002. 60 Cash provided by financing activities in the six months ended June 30, 2002 was $39.7 million compared to $8.1 million of cash used in financing activities in the six months ended June 30, 2001, a change of $47.8 million. This was primarily attributable to additional debt incurred to finance the reversionary interest purchased from CSX. Net cash provided by operations was $13.1 million in 2001, $10.7 million in 2000 and $13.8 million in 1999. The decrease in 2000, as compared to 2001 and 1999, resulted from a decline in coal royalty revenues due to the idling of two operations in Kentucky and the exhaustion of reserves on one property in West Virginia. The two mines idled in 2000 resumed production in 2001. Net cash provided by investing activities was $2.7 million, $4.0 million and $0.2 million in 2001, 2000 and 1999, respectively. Net cash provided by investing activities relates to proceeds from sales of properties partially offset by capital expenditures. Proceeds from sales of surface land were $3.7 million, $4.0 million and $0.2 million in 2001, 2000 and 1999, respectively. Capital expenditures in 2001 increased $8.9 million due to the acquisition of the reversionary interest from the previous owner of the properties. A portion of this acquisition was financed with a $7.9 million note payable to the seller of the reversionary interest. Cash flows from financing activities were $15.4 million in 2001, $14.6 million in 2000 and $14.6 million in 1999. This activity reflects principal repayments on debt, distributions to partners and the placement of cash in restricted accounts as required under the loan agreement. Great Northern Properties Limited Partnership Net cash used in financing activities was $2.5 million in the six months ended June 30, 2002 compared to $3.1 million in the six months ended June 30, 2001. This decrease was the result of a decrease in the amount of cash placed in restricted accounts as required by a loan agreement. Net cash provided by operations was $3.7 million in 2001, $5.7 million in 2000 and $3.2 million in 1999. Cash provided by operating activities in 2000 includes increased accounts receivable collections. Accounts receivable levels declined in 2000 as a result of lower production levels. Net cash provided by investing activities, primarily from proceeds from the sales of surface land, was $475,000, $726,000 and $2,000 in 2001, 2000 and 1999, respectively. Cash flows used in financing activities were $4.6 million in 2001, $6.2 million in 2000 and $3.1 million in 1999. This activity reflects principal repayments on debt, distributions to partners and the placement of cash in restricted accounts as required under the loan agreement. New Gauley Coal Corporation Net cash provided by operations and financing activities in the six months ended June 30, 2002 and 2001 was essentially the same. Net cash provided by operations was $1,323,000, $604,000 and $900,000 for the years 2001, 2000 and 1999, respectively. The decrease in 2000 was primarily the result of a lessee moving onto adjacent property during 2000. Net cash used in investing activities was $175,000, $0, and $67,000 for the years 2001, 2000 and 1999, respectively. This reflects a $200,000 note receivable net of proceeds from asset sales in 2001. Net cash used in financing activities was $1,091,000, $591,000 and $979,000 for the years 2001, 2000 and 1999, respectively. This activity primarily reflects dividends to stockholders. Arch Coal Contributed Properties The Arch Coal Contributed Properties do not maintain cash accounts. Cash receipts and expenditures are maintained by Ark Land. 61 Direct cash flows from the Arch Coal Contributed Properties were $8.6 million in the six months ended June 30, 2002 compared to $9.8 million in the six months ended June 30, 2001. The decrease was a result of decreased coal production from the Arch Coal Contributed Properties during the six months ended June 30, 2002. Direct cash flows from the Arch Coal Contributed Properties were $15.4 million in 1999, $16.6 million in 2000 and $19.8 million in 2001. The increase during the three years was a result of increased coal royalties generated from the Arch Coal Contributed Properties. CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS Description of Credit Facility In connection with the closing of this offering, our operating company will enter into a three year $100 million revolving credit facility. The credit facility includes a $12.0 million distribution loan sublimit that can be used for funding quarterly distributions. The remainder of the revolving credit facility will be available for general, limited partnership and limited liability company purposes, including future acquisitions, but may not be used to fund quarterly distributions. At the closing of this offering, we expect that all of the $100 million credit facility will be available for borrowing. Our obligations under the credit facility will be unsecured but will be guaranteed by us and our operating subsidiaries. We may prepay all loans at any time without penalty. We must reduce all borrowings under the distribution loan subfacility to zero for a period of at least 15 consecutive days once during each twelve-month period. Indebtedness under the revolving credit facility will bear interest, at our option, at either: - the higher of the federal funds rate plus 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 1.25% to 1.75%. We will incur a commitment fee on the unused portion of the credit facility at a rate of 0.50% per annum. The credit facility prohibits us from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the credit agreement, occurs or would result from the distribution. In addition, the credit facility will contain various covenants limiting our operating company's and its subsidiaries' ability to: - incur indebtedness; - grant liens; - engage in mergers and acquisitions or change the nature of our business; - amend our organizational documents or the omnibus agreement; - make loans and investments; - sell assets; or - enter into transactions with affiliates. The credit agreement also contains covenants requiring us to maintain: - a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the credit agreement) of 2.5 to 1.0 for the four most recent quarters; and - a ratio of consolidated EBITDA to consolidated interest expense of 4.0 to 1.0 for the four most recent quarters. 62 If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of any indebtedness outstanding under the credit agreement and exercise other rights and remedies. Each of the following will be an event of default: - failure to pay any principal, interest, fees or other amount when due; - failure to pay any indebtedness, other than indebtedness under the credit facility, in excess of $1 million when due or the occurrence and continuance of any other default beyond the applicable grace period, if any, if the default permits or causes the acceleration of the indebtedness or termination of any commitment to lend; - bankruptcy or insolvency events; - termination of existence; - failure to comply with the loan documents, subject to certain grace periods; - any representation, warranty or document provided is determined to have been materially untrue when made or provided; - entry and the failure to pay, bond, stay or contest adverse judgments or similar processes in excess of $1 million more than any applicable insurance coverage; and - any of the following changes in control: - we cease to own all of the member interests of the operating company; - our general partner ceases to own directly all of our general partner interests; or - Corbin J. Robertson, Jr. and the WPP Group and/or one or more of their direct or indirect subsidiaries cease to own more than 50% of the partnership interests of our general partner. The credit facility is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation. Partnership Agreement Our general partner will not receive any management fee or other compensation for its management of Natural Resource Partners. However, in accordance with the partnership agreement, our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. All direct general and administrative expenses will be charged to us as incurred. Indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates will be reimbursed. Cost reimbursements and fees due our general partner may be substantial and will reduce our cash available for distribution to unitholders. For additional information, please read "Certain Relationships and Related Transactions -- Omnibus Agreement." INFLATION Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the years ended December 31, 1999, 2000 or 2001. 63 ENVIRONMENTAL The operations of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of substantially all of our leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. However, if a particular lessee is not financially capable of fulfilling those obligations, there is a possibility that regulatory authorities could attempt to assign the liabilities to us as the landowner. We would contest such an assignment. Please read "Risk Factors -- Regulatory and Legal Risks" and "Business -- Regulation." RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The adoption of SFAS No. 133 on January 1, 2001 did not have a material impact on the WPP Group's or the Arch Coal Contributed Properties' historical financial position or results of operations. In June 2001, the FASB issued SFAS No. 141 "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 eliminates pooling-of-interests accounting and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. With regard to intangible assets, SFAS No. 141 states that intangible assets acquired in a business combination subsequent to June 30, 2001 should be recognized separately if the benefit of the intangible asset is obtained through contractual rights or if the intangible asset can be sold, transferred, licensed, rented or exchanged, without regard to the acquirer's intent. The adoption of SFAS No. 141 did not have a material impact on the 2001 financial statements. SFAS No. 142 discontinues goodwill amortization; rather, goodwill will be subject to at least an annual fair-value based impairment test. The adoption of SFAS No. 142 on January 1, 2002 did not have a material impact on our financial statements. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. We are evaluating the future financial effects of adopting SFAS No. 143 and expect to adopt the standard effective January 1, 2003. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The objective of SFAS No. 144 is to establish one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. The adoption of SFAS No. 144 on January 1, 2002 did not have a material impact on our financial position or results of operations. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 62, Amendment of FASB Statement No. 13, and Technical Corrections." Among other things, SFAS No. 145 will require gains and losses on extinguishments of debt to be classified as income or loss from continuing operations rather than as extraordinary items as previously required under SFAS No. 4. The provisions of this Statement related to the rescission of SFAS No. 4 will be applied in fiscal years beginning after 64 May 15, 2002. We do not expect the adoption of SFAS No. 145 on January 1, 2003 to have a material impact on our financial position or results of operations. In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." The principal difference between SFAS No. 146 and Issue 94-3 relates to SFAS No. 146's requirements for recognition of a liability for a cost associated with an exit or disposal activity. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue 94-3, a liability for an exit cost as generally defined in Issue 94-3 was recognized at the date of an entity's commitment to an exit plan. A fundamental conclusion reached by the FASB in SFAS No. 146 is that an entity's commitment to a plan, by itself, does not create an obligation that meets the definition of a liability. Severance pay under SFAS No. 146, in many cases, would be recognized over time rather than up front. The FASB decided that if the benefit arrangement requires employees to render future service beyond a "minimum retention period" a liability should be recognized as employees render service over the future service period even if the benefit formula used to calculate an employee's termination benefit is based on length of service. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. CRITICAL ACCOUNTING POLICIES Coal Royalties. We recognize coal royalty revenues on the basis of tons of coal sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalty payments are generally recoupable over certain time periods. We initially record minimum payments as deferred revenue and recognize them as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires. Timber Royalties. We sell timber on a contract basis where independent contractors harvest and sell the timber and, from time to time, in a competitive bid process involving sales of standing timber on individual parcels. We recognize timber revenues when the timber has been sold or harvested by the independent contractors. Title and risk of loss pass to the independent contractors when they harvest the timber. Depletion. We deplete coal properties on a units-of-production basis by lease based upon coal mined in relation to the net cost of the mineral properties and estimated proved and probable tonnage therein. We estimate proved and probable coal reserves with the assistance of third-party mining consultants and involve the use of estimation techniques and recoverability assumptions. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. Timberlands are stated at cost less depletion. We determine the cost of the timber harvested based on the volume of timber harvested in relation to the amount of estimated net merchantable volume by geographic areas. We estimate our timber inventory using statistical information and data obtained from physical measurements and other information gathering techniques. These estimates are updated annually and may result in adjustments of timber volumes and depletion rates, which are recognized prospectively. Changes in these estimates have no effect on our cash flow. During 1999, Arch Coal determined that as a result of several adverse regulatory rulings and the continued negative pricing trends related to Central Appalachian coal production experienced by Arch Coal at that time, an evaluation of the recoverability of its active mining operations and coal reserves was necessary pursuant to SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The evaluation indicated that the future undiscounted cash flows of certain coal reserves were below the carrying value of such assets. Accordingly, Arch Coal adjusted the value of certain reserves. The estimated fair value for the coal reserves with no future mine plans was based upon the fair value of these properties to be derived 65 from leasing operations. The Arch Coal Contributed Properties affected by the write-down were written down to approximately $47.1 million, resulting in a non-cash impairment charge of $65.2 million. As a result of this adjustment, we decreased the depletion rates for the affected properties. Except for the impairment charge in 1999, there have been no other adjustments to these estimates in each of the last three years which had a material impact on the financial results. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and coal price risk. Debt we incur under our credit facility will bear variable interest at either the applicable base rate or a rate based on LIBOR. Unless interest rates increase significantly in the future, our exposure to interest rate risk should be minimal. Please read "Coal Industry Overview -- Coal Prices" for a discussion of coal price exposure risk. 66 COAL INDUSTRY OVERVIEW We obtained the information provided in this Coal Industry Overview regarding coal consumption, coal market prices and other data from the Energy Information Administration, the independent statistical and analytical agency within the U.S. Department of Energy, which we refer to in this prospectus as "EIA," as well as Platts Global Energy, a division of The McGraw-Hill Companies, Inc., which we refer to in this prospectus as "Platts," and the National Mining Association, the primary trade association for the coal industry, which we refer to in this prospectus as "NMA." The EIA bases its forecasts on assumptions about, among other things, trends in various economic sectors, including the residential, transportation and industrial sectors, economic growth rates, technological improvements and demand for other energy sources. Unless we indicate otherwise below, we have obtained the information in this Coal Industry Overview from the EIA. INTRODUCTION Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel for the generation of electric power. World-wide recoverable coal reserves are estimated to be approximately 1.1 trillion tons. The United States is the world's second largest producer of coal and has approximately 25% of global coal reserves, representing approximately 250 years of supply based on current usage rates. Coal reserves in the United States represent approximately 95% of the nation's total fossil fuel reserves. COAL MARKETS Coal is primarily consumed by utilities to generate electricity, by steel companies to make steel products with blast furnaces and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In general, coal is characterized by end use as either steam coal or metallurgical coal. Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coke, which is used in the production of steel. Over the past quarter century, total coal consumption in the United States has nearly doubled to approximately 1.1 billion tons in 2001. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators. Continued demand for coal will primarily depend on coal consumption patterns of the electricity and steel industries and the industrial sector, and the availability, location and price of alternative fuel sources such as natural gas, oil, nuclear and hydroelectric power. The following table sets forth historical and projected demand trends for U.S. coal by end use consumer through 2020. COAL DEMAND BY END USE CONSUMER

PROJECTED ANNUAL GROWTH 2000- 1999 2000 2001(E) 2005(F) 2010(F) 2015(F) 2020(F) 2020 ----- ----- ------- -------- -------- ------- ------- ---------------- (TONS IN MILLIONS) END USE CONSUMER: Electricity Generation.......... 947 983 957 1,065 1,141 1,183 1,254 1.2% Industrial...................... 65 65 63 80 81 83 86 1.4% Steel Production................ 28 29 26 26 24 22 20 (1.8%) Residential/Commercial.......... 5 4 4 5 5 6 6 2.0% Export.......................... 58 58 49 56 54 53 55 (0.3%) ----- ----- ----- ----- ----- ----- ----- Total......................... 1,103 1,139 1,099 1,232 1,305 1,347 1,421 1.1% ===== ===== ===== ===== ===== ===== =====

--------------- (e) estimated (f) forecasted Source: EIA Annual Energy Outlook 2002 and EIA Monthly Energy Review, August 2002. 67 Over the past ten years, coal-fired power plants have produced over 50% of the electricity in the United States. Coal is the principal source of fuel for electric utilities because of its relative low cost and availability throughout the United States. The following table sets forth the fuel sources for the generation of electric power in the United States for the last five years. DOMESTIC ELECTRIC POWER GENERATORS' FUEL SOURCES COMPARISON

1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- FUEL SOURCE: Coal.................................................. 53% 52% 51% 52% 51% Nuclear............................................... 18% 19% 20% 20% 20% Conventional hydroelectric............................ 10% 9% 9% 7% 6% Natural gas(1)........................................ 14% 15% 15%(e) 16%(e) 17%(e) Other................................................. 5% 5% 5%(e) 5%(e) 6%(e) --- --- --- --- --- Total................................................. 100% 100% 100% 100% 100% === === === === ===

--------------- (1) Includes supplemental gaseous fuels. (e) estimated Source: EIA Monthly Energy Review, August 2002. Coal's primary advantage is its relative low cost compared to other fuels used to generate electricity. On an average cost per megawatt-hour basis, coal-fired generation is substantially less expensive than electricity generated utilizing natural gas, oil or nuclear power. Hydroelectric power is less expensive but is limited geographically, and there are few suitable sites for new hydroelectric power dams. The following table sets forth historical delivered fuel prices to electric utilities through 2001. DELIVERED FUEL PRICES TO ELECTRIC UTILITIES

1997 1998 1999 2000 2001(E) ----- ------- ------- ------- ------- (DOLLARS PER MILLION BTUS) FUEL: Petroleum (Heavy Oil)................................. $2.79 $2.08 $2.44 $4.29 $3.72 Natural Gas........................................... 2.76 2.38 2.57 4.30 4.49 Coal.................................................. 1.27 1.25 1.22 1.20 1.23

--------------- (e) estimated Source: EIA Monthly Energy Review, August 2002. INDUSTRY TRENDS In recent years, the coal industry has experienced several significant trends including: Significant Gains in Mining Productivity. U.S. coal production more than doubled from 1968 to 1998 due largely to changes in work practices and the introduction of new technologies that have greatly increased mine productivity. According to Platts, overall coal mine productivity, measured in tons produced per miner shift, has increased from 28.5 tons in 1990 to 55.0 tons in 2000. Growth in Coal Consumption. Coal consumption should continue to expand as demand for electricity continues to increase. According to Platts and EIA, between 1990 and 2000, electricity production by domestic electric power producers has increased 27% and coal consumption by electric power producers has increased 20%. To date, the deregulation in the U.S. electric utility industry is 68 motivating power companies to utilize generating plants with the lowest fuel cost, a trend we believe will continue to contribute to the demand for coal in the future. Industry Consolidation. U.S. coal producers have experienced consolidation over the last 25 years. According to the 1977 Keystone Coal Industry Manual, in 1976, the 10 largest coal companies accounted for approximately 38% of total domestic coal production, whereas in 2001, the 10 largest coal companies accounted for approximately 63% of total domestic coal production. Despite the considerable consolidation, according to Platts the industry still remains relatively fragmented with more than 700 coal producers in the United States. Increased Utilization of Existing Capacity of Coal-Fired Power Plants. We believe that existing coal-fired plants will supply much of the projected increase in the demand for electricity because they possess excess capacity that can be utilized at low incremental costs. The average coal-fired generating plant utilization is projected to increase to 84% in 2020 from 72% in 2000. Restructuring of Electricity Industry. In October 1992, Congress enacted the Energy Policy Act of 1992, which gave wholesale electricity suppliers access to the transmission lines of U.S. utility companies. In May 1996, the Federal Energy Regulatory Commission issued the first of a series of orders establishing rules to promote competition in wholesale electricity markets by providing wholesale electricity suppliers open access to electricity transmission systems. In 1999, the Federal Energy Regulatory Commission issued a rule to encourage the establishment of regional transmission organizations. Wholesale competition has resulted in a substantial increase in non-utility generating capacity in the United States. Increasingly Stringent Air Quality Laws. The coal industry has witnessed a shift in demand to low sulfur coal production driven by regulatory restrictions on sulfur dioxide emissions from coal-fired power plants. In 1995, Phase I of the Clean Air Act required high sulfur coal plants to reduce their emissions of sulfur dioxide to 2.5 pounds or less per million Btu, and in 2000, Phase II of the Clean Air Act tightened these sulfur dioxide restrictions further to 1.2 pounds of sulfur dioxide per million Btu. Currently, electric power generators operating coal-fired plants can comply with these requirements by: - burning lower sulfur coal, either exclusively or mixed with higher sulfur coal; - installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal; - reducing electricity generating levels; or - purchasing or trading emission credits to allow them to comply with the sulfur dioxide emission compliance requirements. Eventually, however, owners of these plants may have to retrofit their operations or switch to burning Phase II compliance coal. We believe that the Clean Air Act will increase the demand for the lower sulfur coal that our lessees produce and sell. However, we believe demand for medium and high sulfur coal will also remain strong in certain markets as many coal-fired power plants continue to burn medium and high sulfur coal, either exclusively or mixed with lower sulfur coal. COAL ROYALTY BUSINESS Coal royalty businesses are principally engaged in the business of owning and managing coal reserves. As an owner of coal reserves, royalty businesses typically are not responsible for operating mines, but instead enter into long-term leases with third-party coal mine operators granting them the right to mine coal reserves on the owner's property in exchange for a royalty payment. A standard lease has a 5 to 10 year base term, with the lessee having an option to extend the lease for additional five-year terms. Leases often include the right to renegotiate rents and royalties for the extended term. Typically, lessees make payments based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold. Therefore, coal royalty revenues are affected by changes in coal prices, lessees' supply contracts and, to a lesser extent, fluctuations in the spot market prices for coal. The 69 prevailing price for coal depends on a number of factors, including the supply-demand relationship, the price and availability of alternative fuels, overall economic conditions and governmental regulations. In addition to their royalty obligation, lessees are often subject to pre-established minimum monthly, quarterly or annual payments. These minimum rentals reflect amounts owners are entitled to receive even if no mining activity occurred during the period. Minimum rentals are often credited against future production royalties that are earned when coal production commences. Because royalty businesses do not operate any mines, they do not bear ordinary operating costs and have limited direct exposure to environmental, permitting and labor risks. As operators, the lessees are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. In addition, the lessees bear the labor risks, including health care legacy costs, black lung benefits and workmen's compensation costs, associated with operating the mines. Royalty businesses typically pay property taxes and then are reimbursed by the lessee for the taxes on the leased property, pursuant to the terms of the lease. LARGEST U.S. COAL PRODUCERS The ten largest coal producers in the United States accounted for 63% of total U.S. production in 2001. Our lessees include subsidiaries of seven of the top 10 coal producing companies in the United States. The following table sets forth the ten largest coal producers in the United States in 2001. TOP TEN U.S. COAL PRODUCERS

PERCENT OF TOTAL TONS IN U.S. COAL COMPANY THOUSANDS PRODUCTION ------- --------- ----------------------- Peabody Energy Corporation*................................. 167,402 15% Arch Coal, Inc.*............................................ 116,377 10% Kennecott Energy & Coal Co.................................. 110,548 10% CONSOL Energy Inc.*......................................... 70,565 6% RAG American Coal Holding Inc.*............................. 65,131 6% Horizon Natural Resources, Inc.*............................ 47,802 4% Vulcan Partners, L.P........................................ 43,049 4% Massey Energy Company*...................................... 42,729 4% Westmoreland Coal Company*.................................. 27,889 2% North American Coal Corp.................................... 26,728 2% ------- -- Total..................................................... 718,220 63% ======= ==

--------------- * A subsidiary of this entity is our current lessee. Source: Platts. IMPORTS AND EXPORTS Coal imports into the United States represent a very small percentage of the total U.S. market for coal. Of the 1.1 billion tons of coal consumed in the United States in 2001, less than 1.9% came from foreign markets. The United States exported approximately 4.3% of 2001 total domestic production. The majority of coal exported from the United States has historically been metallurgical coal. Due to the increase of metallurgical coal available from other countries and technological advances in steel manufacturing, the export market for this coal has not been as attractive in recent years. Approximately 44.8% of U.S. coal exports in 2001 went to Europe, while the individual nations buying the most U.S. coal in 2001 were Canada, Italy, Brazil, Belgium, the United Kingdom and the Netherlands. 70 COAL CHARACTERISTICS There are four types of coal: lignite, subbituminous, bituminous and anthracite. Each has characteristics that make it more or less suitable for different uses. Heat value and sulfur content are two of the most important coal characteristics in determining the best consumer for particular types of coal. Heat Value. The heat value of coal is commonly measured in Btus per pound of coal. A Btu is the amount of heat needed to raise one pound of water one degree Fahrenheit. Coal found in the Eastern and Midwestern regions of the United States tends to have a heat content ranging from 10,000 to 14,000 Btus per pound, as received. As received Btus per pound includes the weight of moisture in the coal on an as sold basis. Most coal found in the Western United States ranges from 8,000 to 10,000 Btus per pound, as received. Our reserves primarily consist of subbituminous and bituminous coal. Unless otherwise stated, all heat values in this prospectus are presented on an as received basis. Lignite is a brownish-black coal with a heat content that generally ranges from 5,000 to 8,300 Btus per pound. Major lignite operations are located in Louisiana, Montana, North Dakota and Texas. Lignite is used almost exclusively in power plants located adjacent to or near these mines because any significant transportation costs, coupled with mining costs, would render its use uneconomical. Subbituminous coal is a black coal with a heat content that ranges from 8,300 to 11,500 Btus per pound. Most subbituminous reserves are located in Alaska, Colorado, Montana, New Mexico, Washington and Wyoming. Subbituminous coal is used almost exclusively by electricity generators and some industrial consumers. Bituminous coal is a soft black coal with a heat content that ranges from 10,500 to 14,000 Btus per pound. This coal is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah, and is the type most commonly used for electricity generation in the United States. Bituminous coal is also used for industrial steam purposes and as metallurgical coal in steel production. Anthracite is a hard coal with a heat content that can be as high as 14,000 Btus per pound. There are a limited number of anthracite deposits primarily located in the Appalachian region of Pennsylvania. Anthracite is used primarily for industrial and home heating purposes. Sulfur Content. Sulfur content can vary from coal seam to coal seam and sometimes within each seam. Coal combustion produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Low sulfur coal has a variety of definitions, but we use it in this prospectus to refer to coal with a sulfur content of 1.0% or less by weight. Compliance coal refers to coal that, when burned, has a sulfur dioxide content of less than 1.2 pounds per million Btus. The strict emissions standards of the Clean Air Act have increased demand for low sulfur coal. We expect continued high demand for low sulfur coal as electricity generators meet the current Phase II requirements of the Clean Air Act. Approximately 65% of our coal reserves are low sulfur coal. Included in our low sulfur reserves is compliance coal, which meets the standards imposed by the Clean Air Act and constitutes approximately 25% of our reserves. Plants equipped with sulfur-reduction technology, known as scrubbers, reduce sulfur dioxide emissions by 50% to 95% and can use higher sulfur coal. Plants without scrubbers can use medium and high sulfur coal by purchasing emission allowances on the open market or blending medium or high sulfur coal with low sulfur coal. Each emission allowance permits the user to emit a ton of sulfur dioxide. Some older coal-based plants have been retrofitted with scrubbers. Any new coal-based generation built in the United States will likely use clean coal technologies to remove the majority of sulfur dioxide, nitrogen oxide and particulate matter emissions. Other Characteristics. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from coal seam to coal seam. Ash content is an important characteristic of coal because it increases transportation costs and electric generating plants must handle and dispose of ash following combustion. 71 Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value per pound of coal, thereby increasing the delivered cost per Btu. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal's weight. COAL MINING TECHNIQUES Coal mining operations use six common techniques to extract coal from the ground. The most appropriate technique is determined by coal seam characteristics such as location and recoverable reserves. Data from core samples is used initially to define the size, depth and quality of the coal reserve area before committing to a specific mining technique. The six most common mining techniques are: continuous, longwall, truck-and-shovel/loader, dragline, highwall and auger. Because coal mining techniques rely heavily on technology, technological improvements have generally resulted in increased productivity. Coal mining technology is continually evolving and has led to improvements in, among other things, underground mining systems and earth-moving equipment for surface mines. For example, longwall mining technology has increased the average recovery of coal from large blocks of underground coal from 50% to 70%. At larger surface mines, haul truck capacity has nearly doubled in the last decade. This increase in capacity, along with larger shovels and draglines, has increased overall mine productivity. Underground Mining Continuous Mining. Continuous mining is an underground mining method in which main airways and transportation entries are developed and continuous miners extract coal from "rooms," leaving "pillars" to support the roof. Production is transported to a beltline for transportation to the surface. Seam recovery for this method is typically up to 60% and productivity for continuous mining averages 25 to 50 tons per miner shift. Longwall Mining. Longwall mining is an underground mining method that uses hydraulic jacks or shields, varying from four feet to twelve feet in height, to support the roof of the mine while a mobile cutting shearer advances through the coal. Chain belts then move the coal to a standard deep mine beltline system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal that are mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive, but it is effective only for large blocks of medium to thick coal seams. High capital costs as well as the cost of moving the equipment from block to block demand large, contiguous reserves. Seam recovery using longwall mining is typically 70% and productivity averages 48 to 80 tons per miner shift. Surface Mining Truck-and-Shovel/Loader Mining. Truck-and-shovel/loader mining is a surface mining method that uses large shovels or loaders to remove overburden, which is used to backfill pits after coal removal. Shovels or loaders load coal into haul trucks for transportation to a preparation plant or unit train loadout facility. Seam recovery using the truck-and-shovel/loader mining method is typically 90%. Productivity depends on equipment, geologic composition and the ratio of overburden to coal. Productivity varies between 250 to 400 tons per miner shift in the Powder River Basin to 30 to 80 tons per miner shift in the Eastern United States. Dragline Mining. Dragline mining is a surface mining method that uses large capacity draglines to remove overburden to expose the coal seams. Shovels load coal in haul trucks for transportation to a preparation plant or unit train loadout facility. Seam recovery using the dragline method is typically 90% or more and productivity levels are similar to those for truck-and-shovel/loader mining. Highwall Mining. Highwall mining is a surface mining method generally utilized in conjunction with truck-and-shovel/loader surface mining. At the highwall exposed by the truck-and-shovel/loader operation 72 a modified continuous miner with an attached beltline system cuts horizontal passages from the surface into a seam. These passages can penetrate to a depth of up to 1,000 feet. This method typically recovers 30% to 40% of the reserve block penetrated. Auger Mining. Auger mining is a surface mining method generally utilized in conjunction with truck-and-shovel/loader operations. At the highwall exposed by a truck-and-shovel/loader operation, a spiral steel auger bit is used to bore a horizontal hole into the coal seam up to a depth of 250 feet. The auger also conveys the coal to the surface. Seam recovery using auger mining is typically 30%. COAL PREPARATION Depending on coal quality and customer requirements, raw coal may be shipped directly from the mine to the customer or processed in a coal preparation plant. Most raw coal requires processing in a preparation plant to meet customer specifications. Preparation plants size coal, wash it in a water solution, remove waste materials and separate coal into grades. This processing increases the quality and heat content of the coal, and ultimately the value, by reducing sulfur, ash and moisture content. Coals of various qualities can be blended at a preparation plant or loading facility to meet specific customer requirements. Coal blending can increase profit margins by optimizing quality specifications for individual customer contracts. COAL REGIONS Coal is mined from coal fields throughout the United States, with the major production centers located in Appalachia, the Illinois Basin and the Western United States. The quality of coal varies by region. Heat value and sulfur content are the two most important coal characteristics in measuring quality and determining the best end use of particular coal types. We have properties located in all three major production centers and in all three subregions of Appalachia. The following table presents U.S. coal production data by region for the five-year period 1997 through 2001. U.S. COAL PRODUCTION

1997 1998 1999 2000 2001 ------- ------- ------- ------- ------- (TONS IN MILLIONS) AREA: Appalachia...................................... 467.8 460.4 425.6 419.4 428.9 Interior United States(1)....................... Illinois Basin................................ 111.6 110.1 104.0 87.2 96.2 Other Interior................................ 59.3 58.3 58.5 56.3 51.5 Western United States(2)........................ 451.3 488.8 512.3 510.7 544.7 ------- ------- ------- ------- ------- Total(3)...................................... 1,089.9 1,117.5 1,100.4 1,073.6 1,121.3 ======= ======= ======= ======= =======

--------------- Source: Coal Industry Annual 2000 and Coal Production by State, July-December 2001, EIA. (1) Our interior coal is located in the Illinois Basin, which is the major production center in the Interior United States. (2) Our western coal is located in the Northern Powder River Basin in Southeastern Montana. (3) Due to rounding, totals may not equal sum of components. 73 Appalachia Region - Northern Appalachia. Northern Appalachia includes Maryland, Ohio, Pennsylvania and Northern West Virginia. Coal from this region generally has a high heat content of between 12,000 and 14,000 Btus per pound. Its typical sulfur content ranges from 1.0% to 4.5%, which does not satisfy the Phase II requirements of the Clean Air Act. - Central Appalachia. Central Appalachia includes Eastern Kentucky, Virginia and Southern West Virginia. Coal from this region generally has a low sulfur content of 0.7% to 1.5% and a high heat content of between 12,000 and 14,000 Btus per pound. Some of this coal satisfies the Phase II requirements of the Clean Air Act. - Southern Appalachia. Southern Appalachia includes Alabama and Tennessee. Coal from this region typically has a low sulfur content of 0.7% to 1.5% and a high heat content of between 12,500 and 14,000 Btus per pound. Some of this coal satisfies the Phase II requirements of the Clean Air Act. Interior United States - Illinois Basin. The Illinois Basin includes Illinois, Indiana and Western Kentucky and is the major coal production center in the Interior United States. There has been significant consolidation among coal producers in the Illinois Basin over the past several years. Coal from this region varies in heat content from 10,000 to 12,500 Btus per pound and has a high sulfur content of 2.0% to 4.0%, which does not satisfy the Phase II requirements of the Clean Air Act. - Other Interior. Other coal-producing states in the Interior United States include Arkansas, Kansas, Louisiana, Mississippi, Missouri, Oklahoma and Texas. The majority of production in the Interior region outside of the Illinois Basin consists of lignite production from Texas. This lignite typically has a heat content of between 5,000 and 9,500 Btus per pound and a sulfur content of between 1.0% and 2.0%, which does not satisfy the Phase II requirements of the Clean Air Act. Western United States - Four Corners. The Four Corners area includes Northwestern New Mexico, Northeastern Arizona, Southwestern Utah and Southeastern Colorado. The coal from this region typically has a sulfur content of 0.75% to 1% and a heat content of between 9,000 and 10,000 Btus per pound. This coal does not satisfy the Phase II requirements of the Clean Air Act. - Uinta Basin. The Uinta Basin includes Western Colorado and Eastern Utah. The coal from this region typically has a sulfur content of 0.50% to 1% and a heat content of between 10,500 and 12,500 Btus per pound. Most of this coal satisfies the Phase II requirements of the Clean Air Act. - Southern Powder River Basin. The Southern Powder River Basin is located in Northeastern Wyoming. This coal has a very low sulfur content of between 0.15% to 1.20% and a low heat content of between 7,500 and 10,000 Btus per pound. Most of this coal satisfies the Phase II requirements of the Clean Air Act. - Northern Powder River Basin. The Northern Powder River Basin is located in Southeastern Montana and Northeastern Wyoming. This coal has a sulfur content of between 0.30% to 1.0% and a heat content of between 8,400 and 10,000 Btus per pound. Most of this coal does not satisfy the Phase II standards of the Clean Air Act. COAL PRICES Coal prices are influenced by a number of factors and vary dramatically by region. The two principal components of the price of coal are the price of coal at the mine, which is influenced by mine operating costs and coal quality, and the cost of transporting coal from the mine to the point of use. The most important criterion to electricity generators when purchasing coal is its delivered cost per million Btus. 74 The following table summarizes average yearly open market steam coal prices for electric power generation for selected areas. AVERAGE COAL PRICES FOR SELECTED AREAS

POUNDS OF SULFUR BTUS PER DIOXIDE PER POUND(1) MILLION BTU(1) ------------------------------------------------ ------------------------------------------ APPALACHIA: Central Appalachia...... greater than 12,500 less than or equal to 1.2 greater than 12,500 1.21-1.80 greater than 12,500 1.81-2.5 less than or equal to 12,500 less than or equal to 1.2 less than or equal to 12,500 1.21-1.80 less than or equal to 12,500 1.81-2.5 Southern Appalachia..... greater than 12,000 1.21-1.80 less than or equal to 12,000 less than or equal to 1.2 less than or equal to 12,000 1.21-1.80 Northern Appalachia..... greater than 12,500 less than or equal to 2.50 greater than 12,500 greater than 2.5 less than or equal to 12,500 greater than 2.5 ILLINOIS BASIN............ greater than 11,300 1.21-1.80 greater than 11,300 1.81-2.50 greater than 11,300 greater than 2.5 less than or equal to 11,300 greater than 2.5 NORTHERN POWDER RIVER BASIN................... greater than 9,000 less than or equal to 1.2 less than or equal to 9,000 1.21-1.80

MAXIMUM PERCENT SULFUR VALUE(S) AT AVERAGE PRICE PER TON OF COAL LIMITING BTU ---------------------------------- CONTENT(2) 1998 1999 2000 2001(3) ------------------------------ ------ ------ ------ ------- APPALACHIA: Central Appalachia...... 0.75 $27.04 $25.14 $26.17 $40.25 0.76-1.13 25.73 23.68 24.56 37.52 1.14-1.56 24.63 22.19 23.64 36.26 0.75 24.68 23.47 23.73 36.46 0.76-1.13 23.29 22.49 22.16 35.10 1.14-1.56 23.07 21.04 21.67 34.21 Southern Appalachia..... 0.73-1.13 26.76 28.03 29.83 34.62 0.72 23.93 26.84 26.88 33.39 0.73-1.13 20.87 23.33 23.39 32.64 Northern Appalachia..... 1.50 24.53 23.60 25.95 38.11 greater than 1.50 23.17 20.68 23.42 33.98 greater than 1.50 21.52 20.05 20.63 29.33 ILLINOIS BASIN............ 0.68-1.02 22.99 21.22 21.56 36.80 1.03-1.41 22.77 20.94 21.34 35.73 greater than 1.41 20.57 19.30 19.65 30.83 greater than 1.41 18.06 17.01 14.50 26.23 NORTHERN POWDER RIVER BASIN................... 0.54 6.84 6.12 6.51 7.25 0.81 4.70 5.58 5.42 8.22

--------------- Source: Platts. (1) Average Btus per pound and pounds of sulfur dioxide per million Btus for spot coals in each quality category over the 1997 -- 2001 period. (2) We have calculated these amounts. The percent sulfur values are the maximum sulfur values for the specified limiting Btu value. Where the limiting Btu value is expressed as "greater than," the percent sulfur value may increase only if the Btu value increases or if the sulfur dioxide value is not limited. Where the Btu value is expressed as "less than," the percent sulfur value is the absolute maximum unless the sulfur dioxide value is not limited. (3) After the rapid increase in coal prices that began in late 2000 and prevailed through most of 2001, spot prices began to decline in late 2001 as demand for coal fell due to unusually warm weather and the sluggish U.S. economy. Price at the Mine. The price of coal at the mine is influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Typically, coal mining operations will begin at the part of the coal seam that is easiest and most economical to mine. As the seam is mined, it becomes more difficult and expensive to mine because the seam either becomes thinner or extends more deeply into the earth, requiring removal of more overburden. Underground mining is generally more expensive than surface mining as a result of high capital costs, including costs for 75 modern mining equipment and construction of extensive ventilation systems and higher labor costs due to lower productivity. In addition to the cost of mine operations, the price of coal at the mine is also a function of quality characteristics such as heat value, sulfur, ash and moisture content. Metallurgical coal has higher carbon and lower ash content as well as other chemical characteristics and is generally priced higher than steam coal produced in the same regions. Generally, our coal royalty revenues are calculated based on price of coal at the mine. Transportation Costs. Coal used for domestic consumption is generally sold free on board at a loading point, and the purchaser normally pays the transportation costs. Most electric power generators arrange long-term shipping contracts with rail or barge companies to assure stable delivery costs. Transportation cost can be a large component of the purchaser's cost. Although our lessee's customers typically pay the transportation costs, access to good transportation is still important to us because the customer may choose a supplier based on the cost of transportation. Trucks and beltlines haul coal over shorter distances, while railroad and barges move coal over longer distances. According to NMA, railroads transport approximately 60% of U.S. coal production. CSX and Norfolk Southern railroads are the dominant carriers in the Eastern United States, and the Burlington Northern Santa Fe and Union Pacific railroads are the dominant carriers in the Western United States. 76 BUSINESS We are a limited partnership recently formed by the WPP Group, the largest owner of coal reserves in the United States other than the U.S. government, and Arch Coal, Inc., the second largest U.S. coal producer. We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2001, we controlled approximately 1.15 billion tons of proven and probable coal reserves in eight states. We do not operate any mines. We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. Our lessees are generally required to make payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, subject to a minimum payment. The WPP Group includes Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation and Great Northern Properties Limited Partnership, three privately-held companies that are primarily engaged in owning and managing mineral properties. Western Pocahontas Properties Limited Partnership was established in connection with the acquisition of properties located in West Virginia, Kentucky, Maryland, Indiana and Alabama from CSX Corporation in 1986. Properties contributed to us by Western Pocahontas Properties Limited Partnership constituted approximately 45% of our reserves as of December 31, 2001. As part of Western Pocahontas Properties Limited Partnership's acquisition of the CSX properties, Western Pocahontas Properties Limited Partnership acquired New Gauley Coal Corporation, which held additional properties in West Virginia. Properties contributed to us by New Gauley Coal Corporation constituted approximately 1% of our reserves as of December 31, 2001. Great Northern Properties Limited Partnership was established with the acquisition in 1992 from Burlington Resources of properties primarily located in Montana. Properties contributed by Great Northern Properties Limited Partnership constituted approximately 14% of our reserves as of December 31, 2001. Arch Coal, Inc. is one of the largest coal producers in the United States and has been acquiring coal properties since 1969 in West Virginia, Kentucky, Illinois and Virginia. The Arch Coal Contributed Properties constituted approximately 40% of our reserves as of December 31, 2001. BUSINESS STRATEGY We intend to execute the following strategies that we believe reflect our competitive strengths: - Maximize royalty revenues from our existing properties. We work with our lessees by providing technical knowledge of our reserves, including information about title and geology. We also review mine plans to assure efficient recovery of reserves and periodically audit our lessees to verify that royalties have been properly paid. We regularly visit mines to assure that the lessees are complying with the lease terms and approved mine plans. Our employees' extensive experience with our properties enables us to use our technical knowledge of the reserves and our knowledge of the coal industry to identify potential lessees who are best suited to develop and market our reserves. - Explore new opportunities with our existing lessees. Our lessees are generally subsidiaries of large coal producers that have long-term plans to expand their operations. We intend to further develop our relationships with our current lessees in order to participate in future opportunities that our lessees may identify for acquiring or leasing new properties. - Add new lessees to diversify our coal mine operator base. We have identified additional public and private coal mine operators that meet our guidelines as qualified lessee candidates. As we expand our royalty business, we will be seeking new lessees to mine our properties. The addition of these new lessees will allow us to further diversify our coal mine operator base. - Expand and diversify our coal reserves. We intend to actively pursue opportunities to expand and diversify our reserves by acquiring additional coal properties that generate royalty income. We will review potential reserve acquisitions in all coal producing regions of the United States in order to acquire marketable reserves that we believe will be attractive to lessees. We expect to fund any 77 acquisitions with borrowings under our credit facility and proceeds from the issuance of our common units. COMPETITIVE STRENGTHS We believe the following competitive strengths will enable us to execute our business strategies successfully: - Our royalty structure generates stable production and cash flow. Our leases provide for royalty rates generally equal to the higher of a percentage of the gross sales price or a fixed price per ton of coal mined, subject to a minimum monthly, quarterly or annual payment. This structure generally allows our production and cash flow to be stable and predictable in periods of low coal prices, while enabling us to benefit during periods of higher coal prices. - We do not directly bear operating costs and risks. Because we do not operate any mines, we do not bear ordinary operating costs and have limited direct exposure to environmental compliance, permitting and labor risks. Our lessees bear the labor risks, such as health care legacy costs, black lung benefits and workmen's compensation costs associated with operating the mines. In addition, we are typically not ultimately responsible for property taxes, which are paid by us but reimbursed by the lessee pursuant to the terms of the lease. - We primarily lease to large lessees that have a diverse customer base. Our royalty income is primarily from leases to subsidiaries of publicly-held coal companies. In 2001, we derived approximately 76% of our revenues from subsidiaries of seven of the top ten coal producers in the United States. These companies have made significant capital investments in the infrastructure on our properties and have effective marketing organizations. Consequently, our reserves are produced, processed and marketed in a highly efficient manner and sold to a diverse group of utilities, steel companies and industrial users. - Our reserves are diverse and strategically located. Our reserves are geographically diverse and cover a broad range of heat and sulfur content. By offering both metallurgical and steam coal, our coal reserves are marketable to a diverse customer base, thereby enabling our lessees to adjust to changing markets and sustain sales volumes and prices. By having reserves in different geographic areas and by having varied types of coal reserves, our lessees are able to serve a broad number of markets and take advantage of changing customer preferences. - We are well-positioned to pursue acquisitions of coal reserves and other minerals. The coal royalty business is highly fragmented and characterized by numerous small entities that present potentially attractive acquisition opportunities. We will be seeking acquisitions that complement our existing coal reserves, allow us to enter into additional coal regions and expand our property portfolio beyond coal to include other minerals. In conjunction with this offering, we are entering into a $100 million credit facility that will give us the ability to take advantage of acquisition opportunities which, combined with our ability to issue additional units, should provide the financial flexibility to pursue acquisitions. Upon the closing of this offering, we anticipate that we will have no outstanding indebtedness. We believe that our affiliation with Arch Coal and the WPP Group will provide us with a competitive advantage in pursuing acquisition opportunities. Both the WPP Group and Arch Coal have proven track records of successfully completing and integrating acquisitions. - We have experienced, knowledgeable management. Our management team has a successful record of managing, leasing and acquiring properties. Each member of our management team has at least 20 years of experience in the mining industry. We believe our management team has a comprehensive understanding of the areas in which our lessees mine coal, the mining environment and the mining operators who serve as our lessees. Furthermore, we believe our management team has the necessary skills and experience to identify and integrate future acquisitions. 78 OUR RELATIONSHIP WITH THE WPP GROUP AND ARCH COAL The WPP Group and Arch Coal have a significant interest in our partnership through their combined ownership of a 78.6% limited partner interest and the 2% general partner interest in our partnership. Both the WPP Group and Arch Coal have a history of successfully completing and integrating acquisitions in the coal industry. We expect to pursue acquisitions with the WPP Group and Arch Coal, as well as with other companies. We may acquire coal reserve properties, other mineral properties or producing coal properties, in which event we would expect to work with a coal producing company that would acquire the mine assets and lease the reserves from us. While our relationship with both the WPP Group and Arch Coal should provide significant benefits to us, it is also a source of potential conflict. In addition, the WPP Group and Arch Coal may engage in substantial competition with us. Please read "Conflicts of Interest and Fiduciary Responsibilities" and "Certain Relationships and Related Transactions -- Omnibus Agreement." COAL RESERVES AND PRODUCTION We present the reserve information for Natural Resource Partners in this prospectus on a pro forma basis as if the reserves had been contributed to us on December 31, 2001. As of December 31, 2001, we controlled approximately 1.15 billion tons of proven and probable coal reserves in eight states located in Appalachia, the Illinois Basin and the Northern Powder River Basin. As of September 1, 2002, our reserves were located on 45 separate properties and are subject to 62 leases with 31 lessees. We own 98% of our reserves and control 2% of our reserves under paid-up leases for which we have paid royalties sufficient to allow us to mine all of the coal reserves attributable to the property without further payment. We own the right to mine coal on approximately 446,000 acres. Reserves are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and technical limitations. All of the estimates of our reserves that we present in this prospectus are of proven and probable reserves, which we define in the glossary. Weir International Mining Consultants has audited Arch Coal's estimates of coal reserves contributed by it as of December 31, 2001, and Stagg Resource Consultants, Inc. has audited the WPP Group's estimates of coal reserves contributed by it as of December 31, 2001. The audits included reviews of reserve maps, data from drill holes, reserve calculation methodologies and assumptions and available quality trend maps. Please see Appendix E, "Coal Reserve Audit Summary Report of Weir International Mining Consultants" and Appendix F, "Coal Reserve Audit Summary Report of Stagg Resource Consultants, Inc." We prepare our reserve estimates from geologic data assembled and analyzed by the staff of geologists and engineers at the WPP Group and Arch Coal. The geologic data is taken from thousands of drill holes, adjacent mine workings, outcrop prospect openings and other sources, including from third parties. These estimates also take into account legal, technical and economic limitations that may keep coal from being mined. Reserve estimates will change from time to time due to mining activities, analysis of new engineering and geologic data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other factors. In areas where geologic conditions indicate potential inconsistencies related to coal reserves, additional drilling is sometimes performed to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes that are spaced closer together. Our lessees' customers burn coal produced from our properties in power plants located east of the Mississippi River and in Montana and Minnesota. Additionally, our metallurgical coal is processed in coke ovens in the Eastern United States, Europe, South America and Asia. Coal produced from our properties is transported by beltline, rail, barge and truck. All of our properties contain and have access to roads or highways. 79 The following table sets forth on a pro forma basis coal royalty revenues we have received from our properties in each of the following areas: Central Appalachia, Northern Appalachia, Southern Appalachia, the Illinois Basin and the Northern Powder River Basin. COAL ROYALTY REVENUES

YEAR ENDED DECEMBER 31, --------------------------- 1999 2000 2001 ------- ------- ------- (IN THOUSANDS) AREA Appalachia Central Appalachia Eastern Kentucky and Virginia...................... $ 9,779 $12,365 $18,029 Southern West Virginia............................. 15,434 11,654 11,406 Northern Appalachia................................... 2,028 1,669 2,268 Southern Appalachia................................... 919 659 624 Illinois Basin.......................................... 2,074 2,345 3,155 Northern Powder River Basin............................. 11,225 7,692 6,951 ------- ------- ------- Total............................................ $41,459 $36,384 $42,433 ======= ======= =======

The following table sets forth production data and reserve information for our properties in each of the following areas: Central Appalachia, Northern Appalachia, Southern Appalachia, the Illinois Basin and the Northern Powder River Basin. PRODUCTION AND RESERVES

PRODUCTION PROVEN AND PROBABLE RESERVES AT YEAR ENDED DECEMBER 31, DECEMBER 31, 2001 ------------------------ --------------------------------- 1999 2000 2001 UNDERGROUND SURFACE TOTAL(1) ------ ------ ------ ----------- ------- --------- (TONS IN THOUSANDS) AREA Appalachia Central Appalachia Eastern Kentucky and Virginia............ 6,007 7,645 11,684 454,838 55,658 510,496 Southern West Virginia............ 9,121 7,587 6,878 221,272 30,223 251,495 Northern Appalachia...... 862 494 809 179,315 5,346 184,661 Southern Appalachia...... 287 206 277 -- 11,929 11,929 Illinois Basin............. 1,761 1,705 2,659 -- 28,398 28,398 Northern Powder River Basin.................... 10,080 7,098 6,683 -- 166,939 166,939 ------ ------ ------ ------- ------- --------- Total................. 28,118 24,735 28,990 855,425 298,493 1,153,918 ====== ====== ====== ======= ======= =========

--------------- (1) Of the 1.15 billion tons of reserves, we control approximately 21.0 million tons in Southern West Virginia under paid-up leases for which we have paid royalties sufficient to allow us to mine all of the coal reserves attributable to the properties without further payment. We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is that portion of low sulfur coal that, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu. As of December 31, 2001, approximately 25% of our reserves met compliance standards for Phase II of the Clean Air Act. Unless otherwise indicated, we present the quality 80 of the coal throughout this prospectus on an as received basis, which assumes 6% moisture for Appalachian reserves, 12% moisture for Illinois Basin reserves and 25% moisture for Northern Powder River Basin reserves. We own both steam and metallurgical coal reserves in Central and Southern Appalachia, and we own steam coal reserves in Northern Appalachia, the Illinois Basin and the Northern Powder River Basin. In 2001, approximately 12% of the coal production from our properties was metallurgical coal. The following table sets forth our estimate of the sulfur content, the typical quality of our coal reserves and the type of coal in each area as of December 31, 2001. SULFUR CONTENT, TYPICAL QUALITY AND TYPE OF COAL

SULFUR CONTENT TYPICAL QUALITY ---------------------------------------------- ------------------------ LOW MEDIUM HIGH COMPLIANCE (LESS THAN (1.0% TO (GREATER HEAT CONTENT SULFUR AREA COAL(1) 1.0%) 1.5%) THAN 1.5%) TOTAL (BTU PER POUND) (%) ---- ---------- ---------- -------- ---------- --------- --------------- ------ (TONS IN THOUSANDS) APPALACHIA Central Appalachia Eastern Kentucky and Virginia........... 168,683 369,630 94,618 46,248 510,496 13,177 0.99 Southern West Virginia........... 95,185 185,370 53,570 12,555 251,495 13,176 0.90 Northern Appalachia.... 12,735 21,029 10,986 152,646 184,661 13,232 2.29 Southern Appalachia.... 11,929 11,929 -- -- 11,929 13,959 0.69 ILLINOIS BASIN........... -- -- 10,103 18,295 28,398 11,457 2.42 NORTHERN POWDER RIVER BASIN.................. -- 166,939 -- -- 166,939 8,444 0.72 ------- ------- ------- ------- --------- Total................ 288,532 754,897 169,277 229,744 1,153,918 ======= ======= ======= ======= =========

TYPE OF COAL -------------------------- AREA STEAM METALLURGICAL(2) ---- ------- ---------------- (TONS IN THOUSANDS) APPALACHIA Central Appalachia Eastern Kentucky and Virginia........... 487,036 23,459 Southern West Virginia........... 120,257 131,239 Northern Appalachia.... 184,661 -- Southern Appalachia.... -- 11,929 ILLINOIS BASIN........... 28,398 -- NORTHERN POWDER RIVER BASIN.................. 166,939 -- ------- ------- Total................ 987,291 166,627 ======= =======

--------------- (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 sub-set 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. COAL LEASES We earn our coal royalty revenues under long-term leases that generally require our lessees to make payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell, with minimum monthly, quarterly or annual payments. We currently lease approximately 95% of our reserves to 31 lessees that operate 54 mines. In the last three years, we have entered into nine new leases covering approximately 3% of our reserves. A typical lease has a five to ten year base term, with the lessee having an option to extend the lease for additional five-year terms after the expiration of the base term. Many leases include the right to renegotiate rents and royalties for the extended term. Of our 62 leases, we will have four leases with Ark Land Company, an affiliate of Arch Coal, covering approximately 9% of our reserves. Please read "Certain Relationships and Related Transactions -- Agreements with Ark Land Company." Substantially all of our leases require the lessee to pay minimum royalties in monthly, quarterly or annual installments, even if no mining activities have begun. Usually, for a period of three to five years from the time of payment of a minimum royalty, the lessee may credit the payment against production 81 royalties. In 2001, the leases on which we received only minimum royalties contained approximately 21% of our reserves and our lessees paid us minimum royalties aggregating $1,073,450. If none of our lessees had produced coal during 2001, we would have received approximately $11,943,254 in minimum royalty payments. Substantially all of our leases impose on the lessee the following obligations: - to obtain and maintain all necessary permits; - to diligently mine the greatest amount of coal possible from the leased property using current mining techniques; - to employ a competent registered professional mining engineer to plan mining development and to plot the development on maps for our review; - to indemnify and hold us harmless for any damages we incur in connection with the lessee's mining operations; - to conduct mining operations in compliance with all applicable federal, state and local laws and regulations, including reclamation and bonding obligations; - to obtain our written consent prior to subleasing or assigning the lease or upon a change of control of the lessee; - to maintain general liability and property damage insurance in amounts we deem reasonable; and - to reimburse us for ad valorem property taxes we pay on the property. Substantially all of our leases grant us the following rights: - to terminate the lease and take possession of the leased premises in the event of a default by the lessee; - to review lessee mine plans and maps; - to enter the leased premises to examine mining operations and to conduct both engineering and financial audits to confirm the amount of coal mined from our properties and the sale price received for the coal by our lessees; and - to retain all rights to the leased premises other than the right to mine coal, including the right to use the surface of the leased property where we possess that right. In addition, each lease provides that we expressly deny any warranty as to the quality or quantity of coal on our property. Additionally, we do not ensure that the lessees have surface access. Our lessees are responsible for all processing and transportation of coal mined from our properties. We do not own any coal processing or transportation facilities. CENTRAL APPALACHIA (EASTERN KENTUCKY AND VIRGINIA) Our Eastern Kentucky and Virginia properties are comprised of seven properties on approximately 140,000 acres. As of December 31, 2001, these properties contained 510 million tons of coal reserves. The typical quality of the coal produced from these properties is 0.99% sulfur and 13,177 Btus per pound. Production for these properties was 11.7 million tons for the year ended December 31, 2001. As of December 31, 2001, we leased more than 90% of our reserves on these properties to 11 lessees under 15 leases. 82 [Map showing the location of properties in Eastern Kentucky and Virginia] The following table sets forth production data and reserve information with respect to our properties in Eastern Kentucky and Virginia. CENTRAL APPALACHIA PROPERTIES -- EASTERN KENTUCKY AND VIRGINIA

PRODUCTION PROVEN AND PROBABLE YEAR ENDED DECEMBER 31, RESERVES AT DECEMBER 31, 2001 ------------------------- ------------------------------- PROPERTY 1999 2000 2001 UNDERGROUND SURFACE TOTAL -------- ------ ------ ------- ----------- ------- ------- (TONS IN THOUSANDS) Evans-Laviers (KY)............. 1,818 1,195 3,813 63,007 43,711 106,718 Lynch (KY)..................... 163 2,075 3,138 307,679 2,401 310,080 Lone Mountain (KY)............. 2,052 2,227 2,773 49,341 -- 49,341 Pardee (KY) (VA)............... 1,635 1,560 1,344 17,125 3,672 20,797 Chesapeake Mineral (KY)........ 339 243 460 11,933 730 12,663 Johnson County (KY)............ -- 345 156 5,328 4,344 9,672 Elkhorn (KY)................... -- -- -- 425 800 1,225 ----- ----- ------ ------- ------ ------- Total........................ 6,007 7,645 11,684 454,838 55,658 510,496 ===== ===== ====== ======= ====== =======

83 The following is a summary of our major income producing properties in Eastern Kentucky and Virginia. Evans-Laviers. The Evans-Laviers property is located in Breathitt, Floyd, Knott and Magoffin Counties, Kentucky. As of December 31, 2001, the property included 107 million tons of medium and high sulfur coal. We lease the property to CONSOL of Kentucky Inc., a subsidiary of publicly-held CONSOL Energy Inc., which operates an underground mine and contracts the operations of other mines to third-party operators. Additionally, a sublessee operates a surface and highwall mine on the property. The underground mine is on our property as well as adjacent property. The coal produced from this property is trucked to the Big Sandy River for barge transport or is transported by truck or beltline to preparation plants located on-site and on adjacent property. Coal is shipped from the preparation plants on the CSX railroad to customers such as DuPont, Virginia Electric Power, Southern Company, American Electric Power and Electric Fuels. Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky. As of December 31, 2001, this property contained 310 million tons of reserves, 94% of which were low sulfur coal. We primarily lease the property to Resource Development, L.L.C., an independent coal producer. Production comes from underground mines and a surface mine. Production from the mines is transported by truck to a preparation plant on the property and is shipped primarily on the CSX railroad to utility customers such as Georgia Power and Orlando Utilities. Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. As of December 31, 2001, this property contained 49 million tons of reserves, 90% of which were low sulfur coal. We lease the property to Ark Land Company, a subsidiary of publicly-held Arch Coal, Inc. Production comes from underground mines. Production from the mines is transported primarily by beltline to a preparation plant on adjacent property and shipped on the Norfolk Southern or CSX railroads to utility customers such as Georgia Power and the Tennessee Valley Authority. Pardee. The Pardee property is located in Letcher County, Kentucky and Wise County, Virginia. As of December 31, 2001, this property contained 21 million tons of reserves, 82% of which were low sulfur coal. We lease the property to Ark Land. Production comes from underground mines and a surface mine. Production from the mines is transported by truck or beltline to a preparation plant on the property and is shipped primarily on the Norfolk Southern railroad to utility customers such as Georgia Power and the Tennessee Valley Authority. 84 CENTRAL APPALACHIA (SOUTHERN WEST VIRGINIA) Our Southern West Virginia properties are comprised of 17 properties on approximately 125,000 acres. As of December 31, 2001, these properties contained 251 million tons of coal reserves. The typical quality of the coal produced from these properties is 0.90% sulfur and 13,176 Btu per pound. Production from these properties was 6.9 million tons for the year ended December 31, 2001. As of December 31, 2001, we leased more than 90% of our reserves on these properties to 12 lessees under 22 leases. [Map showing the location of properties in Southern West Virginia] 85 The following table sets forth production data and reserve information for our properties in Southern West Virginia. CENTRAL APPALACHIA PROPERTIES -- SOUTHERN WEST VIRGINIA

PRODUCTION PROVEN AND PROBABLE YEAR ENDED DECEMBER 31, RESERVES AT DECEMBER 31, 2001 ------------------------ ------------------------------- PROPERTY 1999 2000 2001 UNDERGROUND SURFACE TOTAL -------- ------ ------ ------ ----------- ------- ------- (TONS IN THOUSANDS) Eunice.......................... 3,096 3,113 1,842 7,788 6,895 14,683 Campbell's Creek................ 1,244 1,312 1,258 10,903 -- 10,903 Y&O............................. 1,249 734 853 49,030 15,478 64,508 Kingston........................ 1,147 942 740 10,708 -- 10,708 Dorothy-Sarita.................. 915 351 652 30,068 -- 30,068 Rockhouse Fork.................. 570 470 322 10,393 -- 10,393 Boone/Lincoln................... 804 604 670 13,815 4,839 18,654 West Fork....................... -- -- 222 11,270 821 12,091 Welch/Wyoming................... -- -- 221 38,481 -- 38,481 Sharp-McMillen.................. 89 61 98 337 872 1,209 Skillet Fork.................... 7 -- -- 340 -- 340 Clay-Nicholas................... -- -- -- 17,393 -- 17,393 Hare............................ -- -- -- 2,707 500 3,207 Jones-Gibson.................... -- -- -- 1,196 -- 1,196 Newberry-Ritter................. -- -- -- 5,605 616 6,221 Wehrle-Casto.................... -- -- -- -- 202 202 Weirwood........................ -- -- -- 11,238 -- 11,238 ----- ----- ----- ------- ------ ------- Total...................... 9,121 7,587 6,878 221,272 30,223 251,495 ===== ===== ===== ======= ====== =======

The following is a summary of the major income-producing properties in Southern West Virginia. Eunice. The Eunice property is located in Raleigh and Boone Counties, West Virginia. As of December 31, 2001, this property included 15 million tons of reserves, 84% of which were low sulfur coal. We lease the property to Boone East Development Co., a subsidiary of publicly-held Massey Energy Company. Boone East Development, through affiliates, conducts two operations on the property, including a surface operation and an underground (longwall) mine. These operations extend onto adjacent reserves and will also extend onto a portion of our nearby Y&O property. Production from this operation is generally transported by beltline and processed at two preparation plants located off the property. The preparation plants ship both metallurgical and steam coal on the CSX railroad to customers such as American Electric Power, CINergy, Louisville Gas & Electric, Virginia Electric Power, AK Steel and U.S. Steel. Campbell's Creek. The Campbell's Creek property is located in Kanawha County, West Virginia. As of December 31, 2001, this property contained 11 million tons of reserves, all of which were low sulfur coal. The property is leased to Ark Land. Production comes from an underground mine and is transported by truck to an on-site preparation plant. After preparation, the coal is trucked to various loading points for shipment by barge, or directly to customers such as Dayton Power & Light, Ohio Edison, Kentucky Utilities and Union Carbide. Y&O. The Y&O property is located in Boone County, West Virginia. As of December 31, 2001, the property contained 65 million tons of reserves, 86% of which were low sulfur coal. The property is subject to four coal leases. Two of the leases are with Boone East Development and the remaining two leases are 86 with Cook Mountain Coal Company and Eastern Associated Coal Corp., subsidiaries of publicly-held Peabody Energy Corporation. The Cook Mountain lease was inactive during 2001 because mining occurred on adjacent property and production from the Eastern Associated Coal lease exhausted the small reserve block being mined. The Boone East leases cover the majority of reserves on the property. Production during 2001 on the leases was from underground mines. Production from the Cook Mountain lease is transported by beltline to a preparation plant owned by Peabody Energy. Both high-volatile metallurgical and steam coal are shipped on the CSX railroad from the plant to customers such as American Electric Power, Carolina Power and Light, Corus and Acominas. Production from the Boone East leases is conveyed by beltline to an off-site preparation plant, which ships both metallurgical and steam coal on the CSX railroad to customers such as American Electric Power, CINergy, Louisville Gas & Electric, Virginia Electric Power, AK Steel and U.S. Steel. A subsidiary of Massey Energy controls an on-site preparation plant with CSX rail service, although the plant is currently inactive. Kingston. The Kingston property is located in Fayette and Raleigh Counties, West Virginia. As of December 31, 2001, this property contained 11 million tons of reserves, 66% of which were low sulfur coal. We lease the property to Kingston Resources, a subsidiary of RAG American Coal Corporation. In 2001, production came from an underground mine and a surface mine. Production from the underground mine is transported by truck to a preparation plant on the property, after which it is trucked to various loading points for shipment by rail or barge, and production from the surface mine is trucked directly to the loading facility. Most of the coal on this property is sold to metallurgical coal customers. Dorothy-Sarita. The Dorothy-Sarita property is located in Raleigh County, West Virginia. As of December 31, 2001, this property included 30 million tons of reserves, 21% of which were low sulfur coal. We lease the property to Black King Mine Development Co., a subsidiary of Massey Energy. In 2001, production from this property was primarily from underground mines and a surface mine. Production from these mines is transported by beltline or truck to a preparation plant located on an adjacent property. Both high-volatile metallurgical and steam coal are shipped on the CSX railroad from the plant to customers such as AK Steel, U.S. Steel, American Electric Power and Virginia Electric Power. Rockhouse Fork. The Rockhouse Fork property is located in Raleigh County, West Virginia. As of December 31, 2001, this property contained 10 million tons of reserves, 92% of which were low sulfur coal. The property produces metallurgical coal and is subject to three coal leases, two of which are with affiliates of The Anker Coal Group, Inc. and the third of which is with White Mountain Mining Company LLC. The White Mountain Mining lease and one of the Anker Coal leases are producing from underground mines. The other lease to an Anker Coal Group affiliate is inactive. The coal from the active Anker Coal lease is processed at an on-site preparation plant and shipped on the CSX railroad to customers such as AK Steel. The coal from the White Mountain Mining lease is trucked to a preparation plant and shipped on either the Norfolk Southern or CSX railroads to customers such as Citizens Gas & Coke Utility. In June 2002, an involuntary bankruptcy petition was filed against White Mountain Mining by four of its creditors. Although this bankruptcy may impact production from the Rockhouse Fork property, we do not believe it will have a material impact on our results of operations or financial condition. Boone/Lincoln. The Boone/Lincoln property is located in Boone and Lincoln Counties, West Virginia. As of December 31, 2001, this property contained 19 million tons of reserves, 45% of which were low sulfur coal. The property is leased to Ark Land. Production comes from an underground mine and a surface mine and is transported by truck and beltline to a preparation plant on adjacent property. The coal is shipped on the CSX railroad primarily to utility customers such as American Electric Power, Baltimore Gas & Electric and Consumers Power. West Fork. The West Fork property is located in Boone County, West Virginia. The property is leased to Eastern Associated Coal Corp. As of December 31, 2001, this property included 12 million tons of reserves, all of which were low sulfur coal. Production comes from an underground (longwall) mine. During late 2001, this longwall mine moved onto our property from adjacent property, contributing to an increase in production. Production from this mine is conveyed by beltline to an off-site preparation plant 87 and shipped on the CSX railroad to both metallurgical and steam customers such as South Carolina Power and Light, Detroit Edison, Rouge Steel and U.S. Steel. NORTHERN APPALACHIA Our Northern Appalachian properties are comprised of 13 properties on 115,000 acres in Northern West Virginia and Maryland. As of December 31, 2001, these properties contained 185 million tons of coal reserves. The typical quality of the coal produced from our Northern Appalachian properties is 2.29% sulfur and 13,232 Btus per pound. Production on these properties was 809,000 tons for the year ended December 31, 2001. As of December 31, 2001, we leased more than 90% of our reserves on these properties to eight lessees under 16 leases. [Map showing the location of properties in Northern West Virginia and Maryland] 88 The following table sets forth production data and reserve information for our properties in the Northern Appalachian area. NORTHERN APPALACHIA PROPERTIES

PRODUCTION PROVEN AND PROBABLE RESERVES AT YEAR ENDED DECEMBER 31, DECEMBER 31, 2001 ------------------------ ------------------------------------- 1999 2000 2001 UNDERGROUND SURFACE TOTAL ---- ---- ---- ----------- ------------- ------- (TONS IN THOUSANDS) New Gauley (WV)........................... 249 149 441 7,917 -- 7,917 Thomas (WV)............................... 202 159 218 -- 371 371 Stony River (WV).......................... 70 88 60 2,321 2,450 4,771 Beaver Creek (WV)......................... 106 84 55 -- 1,726 1,726 Hampshire (WV)............................ -- -- 21 -- 10 10 Mt. Storm-Elk Garden-Oakmont (WV)......... 20 12 14 20,093 76 20,169 Eastern Pocahontas (MD)................... 215 2 -- 2,311 -- 2,311 Davis Lumber (WV)......................... -- -- -- 604 -- 604 Gauley (WV)............................... -- -- -- 3,221 -- 3,221 Gaymont (WV).............................. -- -- -- 2,508 -- 2,508 Hibbs Run (WV)............................ -- -- -- 34,156 -- 34,156 Sincell (MD).............................. -- -- -- 11,637 713 12,350 Wetzel County (WV)........................ -- -- -- 94,547 -- 94,547 --- --- --- ------- ----- ------- Total................................. 862 494 809 179,315 5,346 184,661 === === === ======= ===== =======

The following is a summary of the major income-producing properties in Northern Appalachia. New Gauley. The New Gauley property is located in Nicholas and Greenbrier Counties, West Virginia. As of December 31, 2001, the property included 8 million tons of reserves, all of which were low sulfur coal. The majority of the property is leased to Green Valley Coal Company, a subsidiary of Massey Energy. Coal is produced from an underground mine and is trucked to a preparation plant on adjacent property. Because of its quality, this coal is consumed in the medium-volatile metallurgical and specialty coal markets by customers such as Citizens Gas, Elkem and Calgon Carbon. Stony River. The Stony River property is located in Grant and Tucker Counties, West Virginia. As of December 31, 2001, the property contained 5 million tons of high sulfur coal. The majority of the property is leased to Buffalo Coal Company, Inc. During 2001, coal was produced from surface mining. Buffalo Coal leases other reserves from us in the area as well as from other parties. A portion of the Buffalo Coal production is sold without processing, and the balance is trucked to Buffalo Coal's off-site preparation plant. This coal is primarily sold and delivered by truck to Virginia Electric Power. Buffalo Coal also can ship coal by rail to utilities such as Potomac Electric Power Company. 89 SOUTHERN APPALACHIA Our Southern Appalachian property is comprised of 24,258 acres in Alabama. As of December 31, 2001, this property contained 12 million tons of coal reserves. The typical quality of the coal produced from our Southern Appalachian property is 0.69% sulfur and 13,959 Btus per pound. Production from this property was 277,000 tons for the year ended December 31, 2001. As of December 31, 2001, we leased all of our reserves on this property to two lessees under two leases. [Map showing the location of property in Alabama] 90 The following table sets forth production data and reserve information for our property in the Southern Appalachian area. SOUTHERN APPALACHIA PROPERTY

PRODUCTION YEAR PROVEN AND PROBABLE RESERVES AT ENDED DECEMBER 31, DECEMBER 31, 2001 ------------------ --------------------------------- 1999 2000 2001 UNDERGROUND SURFACE TOTAL ---- ---- ---- ------------ -------- ------- (TONS IN THOUSANDS) Twin Pines/Drummond (AL)............. 287 206 277 -- 11,929 11,929

The following is a summary of the major income-producing leases in Southern Appalachia. Twin Pines/Drummond: The Twin Pines/Drummond property is located in Cullman County, Alabama. As of December 31, 2001, this property contained 12 million tons of coal, all of which were low sulfur coal. The property is subject to two coal leases. One of the leases is with Twin Pines Coal Company, Inc. and the other is with Drummond Coal Company. In 2001 on the Twin Pines lease, coal was produced from a surface (dragline) mine. Coal produced by Twin Pines Coal Company is shipped by truck without processing to customers such as ABC Coke Division -- Drummond Co., Monsanto and Alabama Power. The other lease with Drummond Coal Company is inactive. 91 ILLINOIS BASIN Our Illinois Basin properties are comprised of five properties on 7,570 acres in Indiana and Illinois. As of December 31, 2001, these properties contained 28 million tons of coal reserves. The typical quality of the coal produced from our Illinois Basin properties is 2.42% sulfur and 11,457 Btus per pound. Production from these properties was 2.7 million tons for the year ended December 31, 2001. As of December 31, 2001, we leased all of our reserves on these properties to three lessees under four leases. [Map showing the location of properties in Illinois] 92 [Map showing the location of properties in Illinois] The following table sets forth production data and reserve information for each of our properties in the Illinois Basin. ILLINOIS BASIN PROPERTIES

PRODUCTION YEAR ENDED PROVEN AND PROBABLE RESERVES AT DECEMBER 31, DECEMBER 31, 2001 --------------------- --------------------------------- PROPERTY 1999 2000 2001 UNDERGROUND SURFACE TOTAL -------- ----- ----- ----- ------------ -------- ------- (TONS IN THOUSANDS) Hocking-Wolford (IN)..................... 1,105 909 1,456 -- 10,760 10,760 Sato (IL)................................ 656 796 950 -- 4,300 4,300 Trico (IL)............................... -- -- 253 -- 2,149 2,149 Cummings (IN)............................ -- -- -- -- 1,499 1,499 Peabody Mine #48 (IN).................... -- -- -- -- 9,690 9,690 ----- ----- ----- ---- ------ ------ Total.......................... 1,761 1,705 2,659 -- 28,398 28,398 ===== ===== ===== ==== ====== ======

93 The following is a summary of our major income producing properties in the Illinois Basin. Hocking-Wolford/Cummings. The Hocking-Wolford property and the Cummings property are both located in Sullivan County, Indiana. As of December 31, 2001, these two properties contained 12 million tons of medium and high sulfur coal. Both properties are under common lease to Black Beauty Coal Company, an affiliate of Peabody Energy. Production is currently from a surface mine, and a dragline is being moved onto the property. Coal is shipped by truck and railroad to customers such as Public Service of Indiana and Indianapolis Power and Light. Sato. The Sato property is located in Jackson County, Illinois. As of December 31, 2001, this property contained 4 million tons of medium sulfur coal. We lease the property to Knight Hawk Coal, LLC. Production comes from a surface mine and is transported by truck to the customer or to a loadout facility for transportation by barge. Other coal is processed at a preparation plant on the property and then trucked to the customer or to the loadout facility. Coal is marketed mainly to utility customers such as Ameren. Trico. The Trico property is located in Perry County, Illinois. As of December 31, 2001, this property contained 2 million tons of high sulfur coal. We lease the property to Knight Hawk Coal, LLC. Production comes from a surface mine and is transported by truck to a preparation plant located on Knight Hawk's Sato lease. The coal is trucked to the customer or to a loadout facility for transportation by barge. Coal is marketed mainly to utility customers such as Ameren. NORTHERN POWDER RIVER BASIN Our Northern Powder River Basin properties are comprised of two properties on 34,032 acres in Rosebud and Treasure Counties, Montana. As of December 31, 2001, these properties contained 167 million tons of reserves. The typical quality of the coal produced from our Northern Powder River Basin properties is 0.72% sulfur and 8,444 Btu per pound. Production from these properties was 6.7 million tons for the year ended December 31, 2001. As of December 31, 2001, we leased all of our reserves on these properties to two lessees under three leases. These properties were part of the original land grant to the Great Northern Railway Company in 1864, and were purchased by Great Northern Properties from Burlington Resources in 1992. As provided in the original land grant, only the odd-numbered sections were conveyed, giving a "checkerboard" appearance to our ownership. The mineral rights on the intervening sections are generally owned either by the federal government or the State of Montana and are under lease to our lessee. 94 [Map showing the location of property in Montana] The following table sets forth production data and reserve information for each of our properties in the Northern Powder River Basin. NORTHERN POWDER RIVER BASIN PROPERTIES

PRODUCTION YEAR ENDED PROVEN AND PROBABLE RESERVES AT DECEMBER 31, DECEMBER 31, 2001 ---------------------- ------------------------------- PROPERTY 1999 2000 2001 UNDERGROUND SURFACE TOTAL -------- ------ ----- ----- ----------- ------- ------- (TONS IN THOUSANDS) Western Energy (MT)................... 7,261 5,690 4,907 -- 163,431 163,431 Big Sky Mine (MT)..................... 2,819 1,408 1,776 -- 3,508 3,508 ------ ----- ----- ---- ------- ------- Total....................... 10,080 7,098 6,683 -- 166,939 166,939 ====== ===== ===== ==== ======= =======

The following is a summary of our major income producing properties in the Northern Powder River Basin. Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. As of December 31, 2001, this property contained 163 million tons of low sulfur reserves. Western Energy Company, a subsidiary of publicly-held Westmoreland Coal Company, has two coal leases on the property with nearly identical provisions. Western Energy produces coal by surface (dragline) mining and the coal is transported by either truck or beltline to the four-unit 2,200-megawatt Colstrip generation station located at the mine mouth. A small amount of coal is transported by truck or the Burlington Northern Santa Fe railroad to other customers. Big Sky Mine. The Big Sky Mine property is located adjacent and to the south of the Western Energy property in Rosebud County, Montana. As of December 31, 2001, this property contained 4 million tons of low sulfur reserves. The coal mined from the Big Sky Mine is slightly lower in sulfur than coal mined from the Western Energy mine due to selective mining techniques. The property is leased to Big Sky Coal Company, a subsidiary of Peabody Energy. Big Sky Coal Company produces coal by surface (dragline) mining. Coal is shipped on the Burlington Northern Santa Fe railroad to utilities such as Minnesota Power and Northern States Power. 95 OTHER OPERATIONS We will have revenue from an overriding royalty arrangement and will have a small amount of revenue from wheelage payments, which are tolls paid for the privilege of transporting coal across or through our property. Additionally, we expect to have minimal revenues from royalties on oil and gas leases and coal bed methane leases. In the aggregate, these operations accounted for less than 5% of our total revenues in 2001 on a pro forma basis. COAL INDUSTRY SALES CONTRACTS Our coal reserves are geographically diverse and cover a broad range of heat and sulfur content. By offering both metallurgical and steam coal, our lessees are able to serve a diverse customer base. This market diversity enables our lessees to adjust to changing market conditions and sustain high sales volumes and prices. Our larger lessees have efficient marketing abilities that provide competitive advantages when negotiating and renewing coal sales contracts. The terms of coal sales contracts are typically the results of both bidding procedures and extensive negotiations with the customers. As a result, the terms of these contracts vary significantly in many respects, including price adjustment features, price and contract reopener terms, permitted sources of supply, force majeure provisions, coal qualities, quantity, flexibility and adjustments. The contracts typically have terms of one to three years and are subject to price adjustment provisions that permit an increase or decrease periodically in the contract price to reflect changes in specified price indices or items such as taxes or royalties or increases and decreases in actual production costs. These provisions, however, may not assure that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can lead to early termination of a contract. Some multi-year contracts also permit the contract to be reopened to renegotiate terms and conditions in addition to price or to terminate the contract. The contracts typically stipulate procedures for quality control, sampling and weighing. Most contracts require operators to deliver coal within ranges for specific coal characteristics such as heat, sulfur, ash, moisture, volatility and other qualities. Failure to meet these specifications can result in economic penalties or termination of the contracts. While most of the contracts specify the approved seams and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location. Although the volume to be delivered pursuant to a contract is stipulated, the buyers often have the option to vary the volume within specified limits. COMPETITION The coal industry is intensely competitive primarily as a result of the existence of numerous producers. Our lessees compete with coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation since 1976, as the top ten producers have increased their share of total domestic coal production from 38% in 1976 to 63% in 2001. This consolidation has led to a number of our lessees' parent companies having significantly larger financial and operating resources than their competitors. Our lessees primarily compete with both large and small producers nationwide. Our lessees compete on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity and steel, as well as environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. 96 REGULATION The coal mining industry is subject to regulation by federal, state and local authorities on matters such as: - the discharge of materials into the environment; - employee health and safety; - mine permits and other licensing requirements; - reclamation and restoration of mining properties after mining is completed; - management of materials generated by mining operations; - surface subsidence from underground mining; - water pollution; - legislatively mandated benefits for current and retired coal miners; - air quality standards; - protection of wetlands; - endangered plant and wildlife protection; - limitations on land use; - storage of petroleum products and substances that are regarded as hazardous under applicable laws; and - management of electrical equipment containing polychlorinated biphenyls, or PCBs. In addition, the electric generating industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our lessees' coal. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on the mining operations of our lessees or their customers' ability to use coal and may require our lessees or their customers to change operations significantly or incur substantial costs. Our lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated completely. Except for the issues associated with the operations of the subsidiaries of Massey Energy noted below, we do not currently expect that future compliance will have a material adverse effect on us, our unitholders or our minimum quarterly distributions. While it is not possible to quantify the expenditures incurred by our lessees to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. Our lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers. Massey Energy Show Cause Order. As discussed in "Risk Factors -- Regulatory and Legal Risks," in January 2002, the West Virginia Department of Environmental Protection entered an order finding a pattern of violations relating to water quality by Marfork Coal Company, a subsidiary of Massey Energy, and suspending its permit for operations adjacent to the Dorothy-Sarita property for 14 days. Marfork Coal filed an appeal and obtained a stay of enforcement of this order. The Surface Mining Board heard the appeal and reduced the suspension to nine days. Marfork Coal has appealed this decision to the circuit 97 court and a hearing has been set for November 22, 2002. The circuit court has granted a stay that will end 60 days following the November 22 hearing. The show cause order issued to Marfork Coal could also have an impact on the longwall mining operations of another subsidiary of Massey Energy, Performance Coal, that are conducted at the Eunice property because coal mined from this part of the Eunice property is sent to the Marfork Coal preparation plant for processing. If this show cause order is not resolved on favorable terms, the permits issued to Massey Energy and its subsidiaries could be suspended or revoked and production could be decreased at the mines on the Dorothy-Sarita property and at the longwall mine operated by Performance Coal at the Eunice property, reducing our coal royalty revenues. If these permits are revoked, Massey Energy and its subsidiaries could be prohibited from obtaining additional permits. In the event of future violations at these properties or at other properties operated by these entities, the existence of those orders may increase the nature and gravity of any sanctions sought in the event that the state decides to pursue any enforcement. Recently, water from a mine operated by Marfork Coal has leaked through the subsurface strata, resulting in a discharge of water into a nearby creek. This discharge is from a mine that is not on our property, but it is possible that Marfork Coal could be subject to further enforcement actions which could impact its ability to continue mining on our property, or that this could be taken into account in connection with the show cause order discussed above. Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of our coal. These regulations can take a variety of forms, as explained below. The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standard for ozone. In particular, coal-fired power plants will be affected by state regulations designed to achieve attainment of the ambient air quality standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead. In July 1997, the EPA adopted more stringent ambient air quality standards for particulate matter and ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA's position, although it remanded the EPA's ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed EPA's adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and the development of new mines by our lessees. This in turn may result in decreased production by our lessees and a corresponding decrease in our coal royalty revenues. Although we cannot predict the future scope of these ozone and particulate matter regulations, future regulations regarding these and other ambient air standards could restrict the market for coal, the development of new mines and our ability to lease coal reserves. This in turn may have a material adverse effect on our royalty revenues. Furthermore, in October 1998, the EPA finalized a rule that will require 19 states in the Eastern United States that have ambient air quality problems to make substantial reductions in nitrogen oxide 98 emissions by the year 2004. To achieve these reductions, many power plants would be required to install additional control measures. The installation of these measures would make it more costly to operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel. Any reduction in coal's share of the electric power generation market could have a material adverse effect on our business, financial condition and results of operations and the business, financial condition and results of operations of our lessees. Along with these regulations addressing ambient air quality, the EPA has initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA's regional haze program could affect the future market for coal from our leases. Furthermore, the imposition of additional control requirements upon our lessees' customers could adversely affect our financial condition or results of operations. Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned electric utility for alleged violations of the Clean Air Act. The EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. Our lessees supply coal to some of the currently affected utilities, and it is possible that other of our lessees' customers will be sued. These lawsuits could require the utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely impact their demand for coal. Any outcome that adversely affects our lessees' customers and their demand for coal could adversely affect our financial condition or results of operations. Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants of greater than 25 megawatt capacity. Affected electric utilities can comply with these requirements by: - burning lower sulfur coal, either exclusively or mixed with higher sulfur coal; - installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal; - reducing electricity generating levels; or - purchasing or trading emission credits. Specific emissions sources receive these credits that electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows its holder to emit one ton of sulfur dioxide. In addition to emissions control requirements designed to control acid rain and to attain the national ambient air quality standards, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009. These controls are likely to require significant new improvements in controls by power 99 plant owners. The most prominently targeted pollutant is mercury, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources. Other proposed initiatives may have an effect upon coal operations. One such proposal is the Bush Administration's recently announced Clear Skies Initiative. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury from power plants. Other so-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of air pollutants. Were such initiatives enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements. In summary, the effect that a variety of Clean Air Act regulations could have on the coal industry and thus our business cannot be predicted with certainty. We cannot assure you that future regulatory provisions will not materially adversely affect our business, financial condition or results of operations. Additionally, we have no ability to control, or specific knowledge regarding, the environmental and other regulatory compliance of purchasers of coal mined from our properties. West Virginia Mountaintop Mining/Valley Fill Litigation. A lawsuit, Bragg v. Robertson, was filed in federal court by the West Virginia Highlands Conservancy and several citizens in July 1998, and generally targeted mountaintop mining operations utilizing valley fills for mine overburden disposal. The plaintiffs in this case alleged that the procedures used by the West Virginia Department of Environmental Protection and the U.S. Army Corps of Engineers for issuing permits for valley fills used in mountaintop removal violated SMCRA, the Clean Water Act and the National Environmental Policy Act. In its ruling on the SMCRA claims, the district court enjoined the West Virginia Department of Environmental Protection from issuing mining permits for the construction of valley fills over both intermittent and perennial stream segments. The Fourth Circuit Court of Appeals vacated the district court's injunction in April 2001, ruling that the Eleventh Amendment to the U.S. Constitution barred suit against the state in federal court for alleged violations of state mining law. The plaintiffs appealed the Fourth Circuit's decision to the U.S. Supreme Court. In January 2002, the U.S. Supreme Court refused to hear the appeal. Because virtually all mining operations in West Virginia, including those of our lessees, utilize valley fills, all or a portion of our lessees' mining operations could have been affected by the permanent injunction. The plaintiffs could file a new lawsuit in state court challenging the West Virginia Department of Environmental Protection's practice of permitting valley fills. If a state court were to enjoin the construction of valley fills, our lessees might not be able to continue mining those reserves in West Virginia that are only accessible through mining techniques that use valley fills, unless such a decision were overturned or if a legislative or other solution were not achieved. The issuance of an injunction by a state court could have a material adverse effect on our lessees and on our acquisition and use of future reserves that require valley fills. The federal defendants had previously reached a settlement with the plaintiffs in December 1998 regarding the Clean Water Act and the National Environmental Policy Act claims. Under the agreement, the U.S. Army Corps of Engineers, in cooperation with other agencies, must prepare a programmatic environmental impact statement regarding the effects of valley fills on the environment. This environmental impact statement was to have been completed by January 2001. At this time, however, the environmental impact statement has not been completed, and it is uncertain when it will be completed. Until the environmental impact statement is completed, an individual Clean Water Act Section 404 dredge and fill permit is required prior to the construction of any valley fill greater than 250 acres in size. Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with 100 black lung and to some survivors of a miner who dies from this disease. Because the regulatory requirements imposed by mine worker health and safety laws are comprehensive and ongoing in nature, non-compliance cannot be eliminated completely. We believe our lessees have made all payments under the Black Lung Act, and are generally in compliance with all applicable mine health and safety laws. Surface Mining Control And Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, our lessees are contractually obligated under the terms of their leases to comply with all laws, including SMCRA and equivalent state and local laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan. Because the regulatory requirements imposed by SMCRA on reclamation and closure are comprehensive and ongoing in nature, non-compliance cannot be eliminated completely. SMCRA also requires our lessees to submit a bond or otherwise financially secure the performance of their reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines. Since our lessees are responsible for these obligations and any related liabilities, we do not accrue for the estimated costs of reclamation and mine closing and we do not pay the tax described above. Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed, according to the regulations, to have "owned" or "controlled" the mine operator. Sanctions against the "owner" or "controller" are quite severe and can include civil penalties, reclamation fees and reclamation costs. We are not aware of any currently pending or asserted claims against us asserting that we "own" or "control" our lessees. Except as disclosed herein regarding the Marfork and Green Valley matters, we believe our lessees are generally in compliance with all operation, reclamation and closure requirements under their SMCRA permits. On March 29, 2002, the U.S. District Court for the District of Columbia issued a ruling that could restrict underground mining activities conducted in the vicinity of public roads, within a variety of federally protected lands, within national forests and within a certain proximity of occupied dwellings. The lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to challenge regulations issued by the Department of Interior providing, among other things, that subsidence and underground activities that may lead to subsidence are not surface mining activities within the meaning of SMCRA. SMCRA generally contains restrictions and certain prohibitions on the locations where surface mining activities can be conducted. The District Court entered summary judgment upon the plaintiff's claims that the Secretary of the Interior's determination violated SMCRA. By order dated April 9, 2002, the court remanded the regulations to the Secretary of the Interior for reconsideration. None of the deep mining activities undertaken on our properties are within federally protected lands or national forests where SMCRA restricts surface mining, even though several are within proximity to occupied dwellings. However, this case poses a potential restriction on underground mining within 100 feet of a public road. If these SMCRA restrictions ultimately apply to underground mining, considerable uncertainty would exist about the nature and extent of these restrictions. The significance of this decision for the coal mining industry remains unclear because this ruling is subject to appellate review. The Department of Interior and the National Mining Association, a trade 101 group that intervened in this action, have appealed the ruling and sought a stay of the order pending appeal to the U.S. Court of Appeals for the District of Columbia Circuit and the stay was granted. If the District Court's decision is not overturned or if some legislative solution is not enacted, this ruling could have a material adverse effect on all coal mine operations that utilize underground mining techniques, including those of our lessees. While it still may be possible to obtain permits for underground mining operations in these areas, the time and expense of that permitting process are likely to increase significantly. Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel. These restrictions or uncertainties could have a material adverse effect on our business. Clean Water Act. Section 301 of the Clean Water Act prohibits the discharge of a pollutant from a point source into navigable waters except in accordance with a permit issued under either Section 402 or Section 404 of the Clean Water Act. Navigable waters are broadly defined to include streams, even those that are not navigable in fact, and may include wetlands. All mining operations in Appalachia generate excess material that must be placed in fills in adjacent valleys and hollows. Likewise, coal refuse disposal areas and coal processing slurry impoundments are located in valleys and hollows. Almost all of these areas contain intermittent or perennial streams, which are considered navigable waters. An operator must secure a Clean Water Act permit before filling such streams. For approximately the past twenty-five years, operators have secured Section 404 fill permits to authorize the filling of navigable waters with material from various forms of coal mining. Operators have also obtained permits under Section 404 for the construction of slurry impoundments although the use of these impoundments, including discharges from them, requires permits under Section 402. Section 402 discharge permits are generally not suitable for authorizing the construction of fills in navigable waters. Our leases require our lessees to obtain all necessary permits required under the Clean Water Act. To our knowledge, our lessees have obtained all permits required under the Clean Water Act and equivalent state laws. On May 8, 2002, the United States District Court for the Southern District of West Virginia issued an order in Kentuckians for the Commonwealth v. Rivenburgh enjoining the Huntington, West Virginia office of the U.S. Army Corps of Engineers from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of overburden from mountaintop mining operations solely for the purpose of waste disposal. These valleys typically contain streams that, under the Clean Water Act, are considered navigable waters of the United States. The court held that the filling of these waters solely for waste disposal is a violation of the Clean Water Act. The effect of this injunction, if it is not overturned by an appellate court or subsequent legislation, will be to make mountaintop mining uneconomical in those areas subject to the injunction. We would be materially affected by this injunction because a substantial number of mountaintop mining valley fill permits required to be obtained by our lessees would need to be issued by the Huntington, West Virginia office of the U.S. Army Corps of Engineers. The court's injunction also prohibits the issuance of permits authorizing fill activities associated with types of mining activities other than mountaintop mining where the primary purpose or use of those fill activities is the disposal of waste. Such activities might include those associated with slurry impoundments and coal refuse disposal areas. If the injunction is not overturned by an appellate court or subsequent legislation, our lessees may not be able to obtain permits in many cases to use these common fill activities, 102 which could render these operations uneconomical. Any consequent reduction or cessation of their operations would reduce mining on our properties and our royalty revenue. Following the issuance of the court's May 8, 2002 order, the plaintiff in the Kentuckians case filed a motion for further injunctive relief requesting that the court require the Huntington, West Virginia office of the U.S. Army Corps of Engineers to revoke the Section 404 valley fill permit identified in the plaintiff's complaint. In addition, various defendants and intervenors filed motions seeking a clarification of the court's order, a stay pending appeal, and a dismissal for failure to join a necessary party. On June 17, 2002, the court ruled on all of the parties' motions. In response to the defendants' motion for clarification, the court decided that its injunction applies to any fill activity that does not have a "constructive primary purpose," citing as an example fills used solely for the disposal of waste. The court noted that such fills could include not only valley fills, but also other mining activities such as refuse impoundments, fills from standard contour or surface mines, or fills related to mine sites with "approximate original contour" waivers. The court noted, however, that determining whether a particular fill has a "constructive primary purpose" is up to the technical expertise of the U.S. Army Corps of Engineers. It also appears that the court would allow the U.S. Army Corps of Engineers to take into consideration post-mining land uses when applying the "constructive primary purpose" test to a particular fill activity. This ruling creates additional uncertainty about how the U.S. Army Corps of Engineers is to apply the "constructive primary purpose" test. Following its discussion of the motion for clarification, the court addressed and denied both the defendants' motion for stay pending appeal and their motion for dismissal. Along with its denials of the defendants' various motions, the court denied the plaintiff's motion for further injunctive relief. Accordingly, the court did not require the U.S. Army Corps of Engineers to revoke the challenged Section 404 permit. The court based its decision on the grounds that it did not have sufficient factual information to determine whether the particular fill at issue had a "constructive primary purpose." The court suggested further that a show cause hearing would be necessary in order for it to make such a determination regarding the validity of an existing permit. In ruling this way, the court left open the possibility that case-by-case challenges to existing permits, including our lessees' permits, could be filed on the basis that the fill activities previously permitted did not have a "constructive primary purpose." Both the U.S. Army Corps of Engineers and the industry parties that have intervened in the lawsuit have appealed this ruling to the Fourth Circuit Court of Appeals. If lawsuits challenging our lessees' permits were successful, our lessees would most likely be required to suspend or cease their surface mining on our properties. If the decision is not overturned on appeal or by new legislation, we would suffer a material decrease in our royalty revenue. West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the EPA's approval of West Virginia's antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. The plaintiffs in this lawsuit, Ohio Valley Environmental Coalition v. Whitman, challenge provisions in West Virginia's antidegradation implementation policy that exempt current holders of National Pollutant Discharge Elimination System (NPDES) permits and Section 404 permits, among other parties, from the antidegradation-review process. Our lessees are current NPDES and/or Section 404 permit holders that are exempt from antidegradation review under these provisions. Revoking this exemption and subjecting our lessees to the antidegradation review process could delay the issuance or reissuance of Clean Water Act permits to our lessees or cause these permits to be denied. If the plaintiffs are successful and if our lessees discharge into waters that have been designated as high-quality by the state, the costs, time and difficulty associated with obtaining and complying with Clean Water Act permits for surface mining of operations could increase, which could in turn increase the costs of coal production, potentially reducing our royalty revenues. 103 Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines that we or our lessees currently own or have previously owned or operated, and sites to which our lessees sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights. We cannot assure you that we or our lessees will not become involved in future proceedings, litigation or investigations or that these liabilities will not be material. Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. We do not hold any mining permits. Under our leases, our lessees are responsible for obtaining and maintaining all permits. In connection with obtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits. Please read "Risk Factors -- Regulatory and Legal Risks." In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically our lessees submit the necessary permit applications between 12 and 18 months before they plan to begin mining a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. In the past, our lessees have generally obtained their mining permits without significant delay. Our lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined by our lessees over the next five years. Our lessees are in the planning phase for obtaining permits for the remaining reserves planned to be mined over the next five years. We cannot assure you, however, that they will not experience difficulty in obtaining mining permits in the future. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the activities of mine operators, including our lessees, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations. We cannot predict the possible effect of such regulatory changes. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. West Virginia Cumulative Hydrologic Impact Analysis Litigation. In a lawsuit unrelated to the Bragg case, two environmental groups sued the West Virginia Department of Environmental Protection in January 2000 in federal court, alleging various violations of the Clean Water Act and SMCRA. The lawsuit was amended in September 2001 to name Gale Norton, Secretary of the Interior, as a defendant. The U.S. Office of Surface Mining is a division within the Department of Interior. The lawsuit, Ohio River 104 Valley Environmental Coalition, Inc. v. Castle, specifically alleges that the West Virginia Department of Environmental Protection has violated its non-discretionary duty to require all surface and underground mining permit applications to include certain stream flow and water quality data and an analysis of the probable hydrologic consequences of the proposed mine, and that the West Virginia Department of Environmental Protection failed to conduct SMCRA-required cumulative hydrologic impacts analysis prior to issuing mining permits. The lawsuit also alleges that the Office of Surface Mining has a non- discretionary duty to apply the federal SMCRA law in West Virginia due to the deficiencies in the state program. In March 2001, the district court denied the plaintiff's motion for a preliminary injunction on its claims against the West Virginia Department of Environmental Protection. In September 2001, the district court denied a motion to dismiss filed by defendant Michael Callaghan, Secretary of the West Virginia Department of Environmental Protection. Callaghan filed an interlocutory appeal of this decision in October 2001. The Fourth Circuit Court of Appeals dismissed this appeal in part and has denied a motion filed by the plaintiffs to dismiss the remaining claims. During the pendency of this appeal, on August 30, 2002, the district court dismissed some of the plaintiffs' claims. If the plaintiffs are eventually successful in this lawsuit, the West Virginia Department of Environmental Protection will have to modify its procedures and requirements for the content and review of mining permit applications, or the federal government will be ordered to assume control over mining permits in West Virginia. Any of these changes are likely to increase the cost of preparing applications and the time required for their review, and may entail additional operating expenditures and, possibly, restrictions on operating that could adversely impact our coal royalty revenues. Green Valley Coal Company, one of our lessees and a subsidiary of Massey Energy Company, intervened as a defendant in this lawsuit because a permit issued to Green Valley is alleged to have been improperly issued, and because several pending Green Valley permit applications are also alleged to be deficient. West Virginia SMCRA Bond Lawsuit. In November 2000, the West Virginia Highlands Conservancy filed a lawsuit in federal district court against the U.S. Department of Interior, the U.S. Office of Surface Mining and the West Virginia Department of Environmental Protection. The lawsuit, West Virginia Highlands Conservancy v. Norton, which seeks declaratory and injunctive relief, generally challenges the adequacy of the two-tier West Virginia alternative reclamation bond program. The first tier requires mine operators to post a bond of up to $5,000 per acre mined. The second tier creates a special reclamation fund which is funded by an assessment on mine operators of three cents per ton of coal. The West Virginia Highlands Conservancy claims that, individually and collectively, the alternative bond reclamation program has inadequate funds to cover the state's cost of conducting mining site reclamation for those sites where the mine operator has defaulted, or might default, on its reclamation obligations. Based upon the alleged inadequacy of the alternative bonding program, the lawsuit claims that the Department of the Interior and the Office of Surface Mining violated their obligations under SMCRA by either (1) not asserting federal control over the West Virginia SMCRA bonding program or (2) not revoking federal approval of the West Virginia SMCRA program and assuming control under SMCRA. The lawsuit also alleges that the West Virginia Department of Environmental Protection (1) failed to ensure that the state bonding program met certain minimum requirements and (2) improperly issued SMCRA permits without requiring mine operators to post sufficient reclamation bonds. In May 2001, the district court dismissed all claims against the West Virginia Department of Environment Protection based upon the principles of sovereign immunity articulated by the Fourth Circuit in the Bragg case. Please read "-- West Virginia Mountaintop Mining/Valley Fill Litigation." The Office of Surface Mining, in June 2001, initiated formal administrative action against the West Virginia Department of Environmental Protection regarding the alleged deficiencies in the state bonding program. The remaining claims in this lawsuit against the federal defendants were the subject of an August 2001 order by the district court. The court denied the federal defendants' motion to dismiss the suit and granted partial summary judgment for the plaintiffs. The court allowed the Office of Surface Mining to continue its administrative action. That action required the West Virginia Department of Environmental 105 Protection to submit proposed new regulatory initiatives to the state legislature's rulemaking committee and, within 45 days of the close of the 2002 legislative session, the state was required to provide final, enacted legislation, signed by the Governor of West Virginia, that addressed all problems with the current state bonding system. The West Virginia Legislature passed, and the Governor of West Virginia signed, an amended alternative bond program, called the 7-Up Plan. The plaintiffs filed a motion in January 2002 asking the court to compel the Office of Surface Mining to perform its non-discretionary duties and find that the new alternative bonding program promulgated by West Virginia still fails to meet the requirements of the federal SMCRA. In March 2002, the court denied the plaintiffs' motion, based in part upon representations by the Office of Surface Mining that it would make a final determination regarding the adequacy of the 7-Up Plan by no later than May 28, 2002. On May 29, 2002, the Office of Surface Mining issued a final rule that approved amendments to the West Virginia alternative bonding scheme adopted by the West Virginia Department of Environmental Protection and enacted by the state legislature. These amendments require, among other things, eliminating the current deficit and restoring the Special Reclamation Fund to solvency, removing spending limitations on the expenditure of funds for water treatment, creating a special advisory council to advise on structural reforms to the bonding program to avoid deficits in the future and annual reporting to the state legislature on the adequacy of the funds in the alternative bonding scheme. The current deficit will be eliminated through special reclamation taxes on clean coal totaling fourteen cents per ton, of which seven cents is an additional temporary tax that will terminate in 39 months. The Office of Surface Mining has projected that these taxes will eliminate the deficit. These taxes and whatever other requirements may be adopted in the future by the advisory council will likely result in increases in the funds that mine operators, including our lessees, are required to post in order to obtain permits and could result in further additional costs or fees related to the operation of a coal mine or the sale of coal. Any changes to the state reclamation bonding program could also complicate and protract the process of applying for and obtaining necessary permits. On June 25, 2002, the West Virginia Highlands Conservancy filed an amended complaint challenging the Office of Surface Mining's approval of the amendments to the West Virginia alternative bonding program. The plaintiff has moved for summary judgment on the bonding issue. Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of endangered species may have the effect of prohibiting or delaying our lessees from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or silvicultural activities in areas containing the affected species. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our lessees' ability to mine coal from our properties in accordance with current mining plans. There can be no assurance, however, that additional species on our properties may not receive protected status under the Endangered Species Act or that currently protected species may not be discovered within our properties. Other Environmental Laws Affecting Our Lessees. Our lessees are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe that our lessees are in substantial compliance with all applicable environmental laws. TITLE TO PROPERTY Of the 1.15 billion tons of proven and probable coal reserves to which we had rights as of December 31, 2001, we owned approximately 1.13 billion, or 98%, of the reserves in fee. We lease approximately 20 million tons, or 2%, of our reserves from unaffiliated third parties. We believe that we 106 have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operations of our business. Some of the leases, easements, rights-of-way, and licenses transferred or to be transferred to us require the consent of the grantor to transfer these rights, although the leases that represent the largest portion of the 20 million tons cited above do not require consent for transfer. We believe that we have obtained or will obtain the third-party consents and authorizations sufficient for the transfer to us of the properties necessary for us to operate our business in all material respects as described in the prospectus. With respect to any consents or authorizations that have not yet been obtained, we believe that those consents or authorizations will be obtained, or that the failure to obtain those consents or authorizations will have no material adverse effect on the operation of our business. For most of our properties, the surface, oil and gas and mineral or coal estates are owned by different entities. Some of those entities are our affiliates. State law and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the existence of the severed estates will materially impede coal development on our properties. EMPLOYEES AND LABOR RELATIONS To carry out our operations, our general partner and its affiliates employ approximately 14 employees who directly support our operations. None of our general partner's employees are subject to a collective bargaining agreement. Some of the employees of our lessees and sublessees are subject to collective bargaining agreements. LEGAL PROCEEDINGS Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See "Business -- Regulation" above for a more complete discussion of our material environmental obligations. 107 MANAGEMENT GP NATURAL RESOURCE PARTNERS LLC WILL MANAGE US Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not, directly or indirectly, participate in our management or operation. Our general partner and GP Natural Resource Partners LLC owe a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a nonrecourse basis. At least two members of the board of directors of GP Natural Resource Partners LLC will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or GP Natural Resource Partners LLC or directors, officers or employees of their affiliates and must meet the independence and experience standards to serve on an audit committee of a board of directors established by the NYSE. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, we will have an audit committee that will consist of independent directors and will review our external financial reporting, recommend engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. Our compensation committee will oversee compensation decisions for the officers of the general partner as well as the compensation plans described below. In compliance with the rules of the NYSE, the members of the board of directors named below will appoint two independent members within three months of the listing of the common units on the NYSE and one additional independent member within 12 months of that listing. The three newly appointed members will serve as the initial members of the conflicts, audit and compensation committees. GP Natural Resource Partners LLC was formed in April 2002. We are managed and operated by the directors and officers of GP Natural Resource Partners LLC, and our management has served in their current capacities since our formation. We expect that most of our operational personnel will be employees of Western Pocahontas Properties Limited Partnership. The officers of GP Natural Resource Partners LLC will spend most of their time managing our business and affairs. These officers may face a conflict, however, regarding the allocation of their time between our business and the other business interests of the WPP Group. GP Natural Resource Partners LLC intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. The board of directors of GP Natural Resource Partners LLC is presently composed of five directors and will be expanded to eight directors upon the appointment of three additional independent directors following the closing of the offering. 108 DIRECTORS AND EXECUTIVE OFFICERS OF GP NATURAL RESOURCE PARTNERS LLC The following table shows information for the directors and executive officers of GP Natural Resource Partners LLC. Executive officers and directors are elected for one-year terms.

ESTIMATED PERCENTAGE OF TIME DEVOTED POSITION WITH TO NATURAL NAME AGE GP NATURAL RESOURCE PARTNERS LLC RESOURCE PARTNERS ---- --- -------------------------------- ----------------- Corbin J. Robertson, Jr. ....... 54 Chief Executive Officer and 50% Chairman of the Board Nick Carter..................... 56 President and Chief Operating 90% Officer Dwight L. Dunlap................ 49 Chief Financial Officer, 90% Secretary and Treasurer Kevin Wall...................... 46 Vice President and Chief 90% Engineer Kenneth Hudson.................. 48 Controller 90% Steven F. Leer.................. 50 Director S. Reed Morian.................. 56 Director David B. Peugh.................. 48 Director W. W. Scott, Jr. ............... 57 Director

Corbin J. Robertson, Jr. is the Chief Executive Officer and the Chairman of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has served as the Chief Executive Officer and Chairman of the Board of the general partners of Western Pocahontas Properties Limited Partnership since 1986, Great Northern Properties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978 and as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986. He also serves as Chairman of the Board of the Baylor College of Medicine and of the Cullen Trust for Higher Education and on the boards of the American Petroleum Institute, the National Petroleum Council, the Texas Medical Center and the World Health and Golf Association. Nick Carter is the President and Chief Operating Officer of GP Natural Resource Partners LLC. He has also served as President of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation since 1990 and as President of the general partner of Great Northern Properties Limited Partnership from 1992 to 1998. Prior to 1990, Mr. Carter held various positions with MAPCO Coal Corporation and was engaged in the private practice of law. He is President of the National Council of Coal Lessors, the immediate past Chair of the West Virginia Chamber of Commerce and a board member of the Kentucky Coal Association. Dwight L. Dunlap is the Chief Financial Officer, Secretary and Treasurer of GP Natural Resource Partners LLC. Mr. Dunlap has served as Vice President-Treasurer of Quintana Minerals Corporation and as Chief Financial Officer, Treasurer and Secretary of the general partner of Western Pocahontas Properties Limited Partnership and Great Northern Properties Limited Partnership since 2000. Mr. Dunlap has worked for Quintana Minerals since 1982 and has served as Vice President and Treasurer since 1987. Mr. Dunlap is a Certified Public Accountant with over 25 years of experience in financial management, accounting and reporting including six years of audit experience with a Big Four international public accounting firm. Kevin Wall is a Vice President and Chief Engineer of GP Natural Resource Partners LLC. Mr. Wall has served as Vice President -- Engineering for the general partner of Western Pocahontas Properties Limited Partnership since 1998 and the general partner of Great Northern Properties Limited Partnership since 1992. He has also served as the Vice President -- Engineering of New Gauley Coal Corporation since 1998. He has performed duties in the land management, planning, project evaluation, acquisition and engineering areas since 1981. He is a Registered Professional Engineer in West Virginia and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers and of the National Society 109 of Professional Engineers. Mr. Wall also serves on the Board of Directors of Leadership Tri-State and is the immediate past president of the West Virginia Society of Professional Engineers. Kenneth Hudson is the Controller of GP Natural Resource Partners LLC. He has served as Controller of the general partner of Western Pocahontas Properties Limited Partnership and of New Gauley Coal Corporation since 1988 and of the general partner of Great Northern Properties Limited Partnership since 1992. He was also Controller of Blackhawk Mining Co., Quintana Coal Co. and other related operations from 1985 to 1988. Prior to that time, Mr. Hudson worked in public accounting. Steven F. Leer is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Leer has also served as President, Chief Executive Officer and a director of Arch Coal, Inc. since 1992. He is also a Director of the Norfolk Southern Corporation, Chairman of the Center for Energy and Economic Development and Chairman of the National Coal Council. S. Reed Morian is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation since 1986 and has served as a member of the Board of Directors of the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian has worked for Dixie Chemical Company since 1971 and has served as its Chairman and Chief Executive Officer since 1981. He has also served as Chairman, Chief Executive Officer and President of DX Holding Company since 1989. David B. Peugh is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Peugh has also served as Vice President -- Business Development of Arch Coal, Inc. since 1993. He is also a director of ZECA Corporation, a company developing an emission-free process of producing electricity from coal. W. W. Scott, Jr. is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Scott was Executive Vice President and Chief Financial Officer of Quintana Minerals Corporation from 1985 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation from 1986 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Great Northern Properties Limited Partnership from 1992 to 1999. Since 1999, he has continued to serve as a director of the general partner of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation. REIMBURSEMENT OF EXPENSES OF OUR GENERAL PARTNER Our general partner will not receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates will, however, be reimbursed for all expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. EXECUTIVE COMPENSATION Our general partner and GP Natural Resource Partners LLC were formed in April 2002. Accordingly, GP Natural Resource Partners LLC paid no compensation to its directors and officers in 2001. We have not accrued any obligations with respect to management incentive or retirement benefits for the directors and officers for 2001. Officers and employees of GP Natural Resource Partners LLC may participate in employee benefit plans and arrangements sponsored by GP Natural Resource Partners LLC or its affiliates, including plans that may be established by the general partner or its affiliates in the future. 110 COMPENSATION OF DIRECTORS No additional remuneration will be paid to officers or employees of GP Natural Resource Partners LLC who also serve as directors. GP Natural Resource Partners LLC anticipates that each director will receive compensation for attending meetings of the board of directors and committee meetings. The amount of compensation to be paid to directors has not yet been determined. The directors who are appointed by Arch Coal, other than the independent director appointed by Arch Coal, will assign any compensation and benefits they receive in their capacity as directors to Arch Coal. In addition, each director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law. LONG-TERM INCENTIVE PLAN GP Natural Resource Partners LLC has adopted the Natural Resource Partners Long-Term Incentive Plan for employees and directors of GP Natural Resource Partners LLC and its affiliates who perform services for us. The long-term incentive plan consists of two components: restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering a number of common units equal to three percent of the number of common units outstanding immediately following the initial public offering of common units. The plan is administered by the compensation committee of GP Natural Resource Partners LLC's board of directors. Subject to the rules of the exchange upon which the common units are listed at the time, GP Natural Resource Partners LLC's board of directors or the compensation committee may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. GP Natural Resource Partners LLC's board of directors or the compensation committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to the rules of the exchange upon which the common units are listed at that time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant. Restricted Units. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, its fair market value in cash. The compensation committee may make grants under the plan to employees and directors containing such terms as the compensation committee shall determine. The compensation committee will determine the period over which restricted units granted to employees and directors will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of Natural Resource Partners, our general partner, or GP Natural Resource Partners LLC. If a grantee's employment or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by GP Natural Resource Partners LLC in the open market, common units already owned by GP Natural Resource Partners LLC, common units acquired by GP Natural Resource Partners LLC directly from us, from another affiliate or any other person or entity or any combination of the foregoing. GP Natural Resource Partners LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. We intend the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units. 111 Unit Options. The long-term incentive plan currently permits the grant of options covering common units. The compensation committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine consistent with the plan. Unit options will have an exercise price that may not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. The compensation committee may base its determination upon the achievement of specified financial objectives. In addition, the unit options will become exercisable upon a change in control as described above. If a grantee's employment or membership on the board of directors terminates for any reason, the grantee's options will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Upon exercise of a unit option, GP Natural Resource Partners LLC will acquire common units in the open market, directly from us, from another affiliate or any other person or entity, or use common units already owned by GP Natural Resource Partners LLC, or any combination of the foregoing. GP Natural Resource Partners LLC will be entitled to reimbursement by us for the difference between the cost incurred in acquiring these common units and the proceeds received from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and GP Natural Resource Partners LLC will pay us the proceeds it received from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders. ANNUAL INCENTIVE PLAN The general partner has adopted the Natural Resource Partners Annual Incentive Compensation Plan. The annual incentive plan is designed to enhance the performance of GP Natural Resource Partners LLC's and its affiliates' key employees by rewarding them with cash awards for achieving annual financial and operational performance objectives. The compensation committee in its discretion may determine individual participants and payments, if any, for each fiscal year. The board of directors of GP Natural Resource Partners LLC may amend or change the annual incentive plan at any time. We will reimburse GP Natural Resource Partners LLC for payments and costs incurred under the plan. 112 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth the beneficial ownership of units of Natural Resource Partners that will be issued upon the consummation of this offering and the related transactions and held by beneficial owners of 5% or more of the units, by directors of GP Natural Resource Partners LLC and by all directors and executive officers of GP Natural Resource Partners LLC as a group. The address of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation is 601 Jefferson Street, Suite 3600, Houston, Texas 77002. The address of Ark Land Company is One CityPlace Drive, Suite 300, St. Louis, Missouri 63141.

PERCENTAGE OF PERCENTAGE OF COMMON UNITS COMMON SUBORDINATED SUBORDINATED PERCENTAGE OF TO BE UNITS TO BE UNITS TO BE UNITS TO BE TOTAL UNITS TO BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY BE BENEFICIALLY NAME OF BENEFICIAL OWNER OWNED OWNED OWNED OWNED OWNED ------------------------ ------------ ------------- ------------ ------------- --------------- Western Pocahontas Properties Limited Partnership.............. 3,158,166 27.8% 5,231,766 46.1% 36.9% Great Northern Properties Limited Partnership...................... 673,715 5.9% 1,116,065 9.8% 7.9% New Gauley Coal Corporation........ 126,107 1.1% 208,907 1.8% 1.5% Arch Coal, Inc.(1)(2).............. 2,895,670 25.5% 4,796,920 42.3% 33.9% Ark Land Company(1)(2)............. 2,895,670 25.5% 4,796,920 42.3% 33.9% Corbin J. Robertson, Jr.(3)........ 3,284,273 28.9% 5,440,673 47.9% 38.4% Nick Carter........................ -- --% -- --% --% Dwight L. Dunlap................... -- --% -- --% --% Kevin Wall......................... -- --% -- --% --% Kenneth Hudson..................... -- --% -- --% --% Steven F. Leer..................... -- --% -- --% --% S. Reed Morian..................... -- --% -- --% --% David B. Peugh..................... -- --% -- --% --% W.W. Scott, Jr. ................... -- --% -- --% --% All directors and executive officers as a group (9 persons)......................... 3,284,273 28.9% 5,440,673 47.9% 38.4%

--------------- (1) Arch Coal, Inc. is the parent company of Ark Land Company and, as such, Arch Coal, Inc. may be deemed to beneficially own the units held by Ark Land Company (2) In the event the underwriters exercise the over-allotment option in full, Ark Land Company will sell 285,187 common units to the underwriters, thereby reducing Arch Coal, Inc.'s and Ark Land Company's beneficial ownership of common units to 2,610,483. (3) Mr. Robertson may be deemed to beneficially own the units held by Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation. 113 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS In March 2001, Arch Coal contacted the WPP Group regarding its interest in forming a limited partnership to hold and lease coal properties and to conduct a public offering of its securities. The WPP Group expressed interest in pursuing the formation of such a partnership and the parties began negotiations and due diligence on the properties to be contributed. In December 2001, the WPP Group and Arch Coal reached preliminary agreement on the structure of the partnership, the properties each party would contribute to the partnership and their relative values and resulting ownership of the general partner and the partnership and agreed to the lead underwriters for the initial public offering of our common units. Arch Coal and the WPP Group continued negotiations on the value of the properties each would contribute to the Partnership and due diligence with respect to these properties and reached final agreement in March 2002. After this offering, affiliates of our general partner will own 6,853,658 common units and 11,353,658 subordinated units representing a 78.6% limited partner interest in us. In addition, our general partner will own the 2% general partner interest in us. Quintana Minerals Corporation, a company controlled by the owner of the general partner of Western Pocahontas Properties Limited Partnership, provided certain administrative services to Western Pocahontas Properties Limited Partnership and charged Western Pocahontas Properties Limited Partnership for direct costs related to the administrative services. The total expenses charged to Western Pocahontas Properties Limited Partnership under this arrangement were approximately $500,000 for each of the years ended December 31, 1999, 2000 and 2001. Western Pocahontas Properties Limited Partnership has a management contract to provide certain management, engineering and accounting services to Great Northern Properties Limited Partnership. The contract provides for, and Great Northern Properties Limited Partnership paid, a $250,000 annual fee, in each of the three years ended December 31, 1999, 2000 and 2001, which is intended to reimburse Western Pocahontas Properties Limited Partnership for its expense. The contract may be canceled upon 90 days advance notice by Great Northern Properties Limited Partnership. Some of the Arch Coal Contributed Properties are leased to affiliates of Arch Coal that mine on the properties. Contracted royalty rates from these affiliates for the three years ended December 31, 2001 were 6.5% of the gross sales price of coal sold from the property using underground mining methods and 7.5% of the gross sales price of coal sold from the property using surface mining methods. Affiliate royalties amounted to $10.5 million, $10.2 million and $10.3 million during the years ended December 31, 2001, 2000 and 1999, respectively. Please read "-- Coal Leases with Ark Land Company" for a discussion of the leases between the Partnership and Ark Land Company. We believe that the terms for each of the above transactions are at least as favorable to us as we would have obtained in transactions negotiated with unaffiliated third parties. DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Natural Resource Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations. FORMATION STAGE The consideration received by our general partner and its affiliates for the contribution of the assets and liabilities to us............. - 6,853,658 common units; - 11,353,658 subordinated units; 114 - 2% general partner interest in Natural Resource Partners; - the incentive distribution rights; and - the assumption of $46.5 million of indebtedness of the WPP Group. OPERATIONAL STAGE 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. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive distributions of approximately $1.0 million on its 2% general partner interest and our affiliates would receive distributions of approximately $15.0 million on their common units and $24.0 million on their subordinated units. 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. See "The Partnership Agreement -- Withdrawal or Removal of the General Partner." LIQUIDATION STAGE Liquidation................... Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances. AGREEMENTS GOVERNING THE TRANSACTIONS We and other related parties have entered into the various documents and agreements that will effect the transactions, including the vesting of assets in, and the assumption of liabilities by, our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm's-length negotiations, and we cannot assure you that they, or that any of the transactions which they provide for, will be effected on terms at least as favorable to the parties to these agreements as they could have been 115 obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering. OMNIBUS AGREEMENT Non-competition Provisions As part of the omnibus agreement to be entered into among Natural Resource Partners, our general partner, the WPP Group, Arch Coal, Ark Land Company and Corbin J. Robertson, Jr. concurrently with the closing of this offering, the WPP Group, any entity controlled by Corbin J. Robertson, Jr. and Arch Coal, which we refer to in this section as the GP affiliates, have each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a "restricted business") in the specific circumstances described below: - the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate owned fee coal reserves within the United States; and - the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate. "Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group, Arch Coal and their respective controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us. Please see "Risk Factors -- The WPP Group and Arch Coal may engage in substantial competition with us." A GP affiliate may, directly or indirectly, engage in a restricted business if: - the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to Natural Resource Partners 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 Natural Resource Partners 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 Natural Resource Partners to purchase these assets under the procedures described below. - its ownership in the restricted business consists solely of a noncontrolling equity interest. For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate. The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in by the WPP Group at closing of the offering, may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be acquired. Arch Coal is not subject to a similar restriction on the total fair market value of restricted businesses it may own. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and the restricted business constitutes greater 116 than 50% of the value of the business to be acquired, then the WPP Group must first offer Natural Resource Partners the opportunity to purchase the restricted business. If (1) Arch Coal desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million or (2) the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer Natural Resource Partners the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph, "restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restriction summarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate. If Natural Resource Partners wants to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, Natural Resource Partners will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by Natural Resource Partners. During this two year period, the GP affiliate may operate the restricted business in competition with Natural Resource Partners, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group. If, at the end of the two year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from the GP affiliate, Natural Resource Partners will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will be under no further obligation to Natural Resource Partners with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group. In addition, if during the two year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offer procedures described above will recommence. If the restricted business to be acquired is in the form of a general partner interest in a publicly-held partnership or a managing member interest in a publicly-held limited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a non publicly-held partnership or a managing member of a non-publicly-held limited liability company, the WPP Group may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures described above. If the restricted business to be acquired is in the form of a general partner interest in a partnership or a managing member interest in a limited liability company, Arch Coal may acquire such restricted business as part of a larger transaction so long as (1) it sells the interest to us or a third party within six months of the acquisition or (2) the general partner, with the approval of the conflicts committee, agrees that the restricted business will be subject to the offer procedures described in the preceding paragraphs without reference again to this paragraph. If, following 117 the six month period, Arch Coal has made a good faith, reasonable attempt to divest the interest, but is unable to do so and Arch has not received an extension from our conflicts committee or has not offered us the opportunity to buy its competing interest, Arch Coal may opt to either (1) have its designated directors immediately resign from the board of directors of our general partner, in which case Arch Coal may continue to own and operate the competing business but will continue to relinquish its rights to designate directors of our general partner until such time as it divests the competing business, or (2) hire an independent investment banking firm to determine the fair market value of the competing business. If Arch Coal elects to obtain an independent valuation of its competing business, then: - if Arch Coal and our general partner (with the concurrence of the conflicts committee) agree upon the price of the competing business, our partnership will purchase the competing business; - if Arch Coal seeks to sell the competing business to our partnership at the price determined by the investment banking firm and our general partner (with the concurrence of the conflicts committee) declines to purchase the competing business, Arch Coal will be free to continue to own and operate the competing business; - if Arch Coal does not wish to sell the competing business to our partnership at the price determined by the investment banking firm and our general partner (with the concurrence of the conflicts committee) seeks to purchase the competing business at such price, then Arch Coal's designated directors must immediately resign from the board of directors of our general partner, in which case Arch Coal may continue to own and operate the competing business. Arch Coal will continue to relinquish its rights to designate directors of our general partner until it divests the competing business. Indemnification Under the omnibus agreement, the WPP Group and Arch Coal, jointly and severally, will indemnify us for (1) three years after the closing of this offering against environmental liabilities associated with the properties contributed to us and occurring before the closing date of this offering and (2) all tax liabilities attributable to the ownership or operation of the partnership assets prior to the closing of this offering. The environmental indemnity will be limited to a maximum amount of $10.0 million. Liabilities resulting from a change in law after the closing of the offering are excluded from the environmental indemnity. The omnibus agreement may be amended at any time subsequent to the offering by the general partner, with the concurrence of the conflicts committee. The respective obligations of the WPP Group and Arch Coal under the omnibus agreement terminate when the WPP Group and its affiliates, or Arch Coal and its affiliates, as the case may be, cease to participate in the control of the general partner. AGREEMENTS WITH ARK LAND COMPANY Concurrently with the closing of the offering of common units, we will enter into four coal mining leases with Ark Land Company, a subsidiary of Arch Coal. The Arch leases grant Arch Coal the right to mine our coal on the following properties: - Lone Mountain located in Kentucky, which contained 49.3 million tons of proven and probable reserves as of December 31, 2001; - Pardee located in Kentucky and Virginia, which contained 20.7 million tons of proven and probable reserves as of December 31, 2001; - Boone/Lincoln located in West Virginia, which contained 18.7 million tons of proven and probable reserves as of December 31, 2001; and - Campbell's Creek located in West Virginia, which contained 10.9 million tons of proven and probable reserves as of December 31, 2001. 118 Coal royalty revenues payable under these leases based on 2001 actual production were $10.5 million, representing 24.8% of our total pro forma coal royalty revenues for the year ended December 31, 2001. If no production had taken place in 2001, minimum royalties of $5.75 million would have been payable under the leases. The Arch leases have an initial term of either eight or ten years, each with an automatic year-to-year extension until the earlier to occur of (1) delivery of notice by Ark Land that it will not renew the lease or (2) all mineable and merchantable coal has been mined. The leases provide for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum per ton of coal Ark Land sells from our properties, with minimum annual royalty payments. Under the Arch leases, minimum royalty payments are credited against future production royalties. The Arch leases are intended to retain some of the legal rights Ark Land possessed when it owned the properties. For this reason, the leases contain some terms and provisions that are different from our third-party coal leases negotiated at arm's length. Some of the more significant differences include: - Ark Land has the ability to sublease the leased property without our prior approval, although Ark Land is still responsible for sublessee performance; - minimum royalty payments from Ark Land continue to be payable during the initial lease term even if all mineable and merchantable coal has been mined from the property; - royalties for coal sold by Ark Land to any of its affiliates may be based on a gross selling price below the market value of the coal; - the indemnities provided by Ark Land to us do not survive the termination of the leases; - we only have a limited ability to terminate the leases; - Arch Coal has royalty-free wheelage rights on the leased properties; and - the leases do not impose a legal duty to diligently mine the maximum amount of coal possible from the leased property. We believe that the production and minimum royalty rates contained in the Arch leases are consistent with current market royalty rates. Ark Land and Arch Coal own an overriding royalty interest in leased coal reserves mined by Black Beauty Coal Company, an affiliate of Peabody Energy, from property located in Knox County, Indiana. Ark Land and Arch Coal will retain the overriding royalty interest following the consummation of this offering. However, ACIN LLC, Ark Land and Arch Coal will enter into an agreement at closing to pass through to ACIN LLC any royalties paid to Ark Land by Black Beauty under the overriding royalty interest, and Arch Coal will guarantee Ark Land's pass-through obligations to the extent of the royalties paid to Ark Land. Annual advance overriding royalty payments, against which production royalties under the leases are credited, are received by Ark Land in June of each year. In 2001, Ark Land received less than $1 million from the overriding royalty interest, or less than 2% of our partnership's 2001 pro forma revenues. The term of the pass-through agreement expires upon the termination of the overriding royalty interest. In May 2002, Ark Land received a notice from Black Beauty asserting that Black Beauty is no longer obligated to pay the $400,000 advance overriding royalty payments to Ark Land associated with a portion of the underlying leased property beginning when the next payment would be due on June 29, 2003. In response, Ark Land has notified Black Beauty that Ark Land disagrees with Black Beauty's right to terminate these payments and intends to assert its right to receive these payments. We cannot assure you as to whether Ark Land will ultimately be successful in this dispute, or whether or when we will receive any or all of the amounts in dispute from Ark Land under our royalty pass-through agreement. 119 CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES CONFLICTS OF INTEREST Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group and Arch Coal) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLC have fiduciary duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the board of directors of our general partner of such resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. In effect, these provisions limit our general partner's fiduciary duties to our unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that might, without those limitations, constitute breaches of fiduciary duty. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is: - approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or course of action that has not received approval; - on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or - fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement, consider: - the relative interests of any party to such conflict and the benefits and burdens relating to such interest; - any customary or accepted industry practices or historical dealings with a particular person or entity; - generally accepted accounting practices or principles; and - such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. Conflicts of interest could arise in the situations described below, among others. ACTIONS TAKEN BY OUR GENERAL PARTNER MAY AFFECT THE AMOUNT OF CASH AVAILABLE FOR DISTRIBUTION TO UNITHOLDERS OR ACCELERATE THE RIGHT TO CONVERT SUBORDINATED UNITS. The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as: - amount and timing of asset purchases and sales; - cash expenditures; - borrowings; 120 - the issuance of additional units; and - the creation, reduction or increase of reserves in any quarter. In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of: - enabling our general partner to receive distributions on any subordinated units held by our general partner or the incentive distribution rights; or - hastening the expiration of the subordination period. For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding units. Please read "Cash Distribution Policy -- Subordination Period." The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries. WE DO NOT HAVE ANY OFFICERS OR EMPLOYEES AND RELY SOLELY ON OFFICERS AND EMPLOYEES OF GP NATURAL RESOURCE PARTNERS LLC AND ITS AFFILIATES. We will not have any officers or employees and will rely solely on officers and employees of GP Natural Resource Partners LLC, its affiliates and the employees of our subsidiaries. Affiliates of GP Natural Resource Partners LLC will conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource Partners LLC will not be required to work full time on our affairs. These officers will devote significant time to the affairs of the WPP Group or its affiliates and will be compensated by these affiliates for the services rendered to them. WE WILL REIMBURSE OUR GENERAL PARTNER AND ITS AFFILIATES FOR EXPENSES. We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. OUR GENERAL PARTNER INTENDS TO LIMIT ITS LIABILITY REGARDING OUR OBLIGATIONS. Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. COMMON UNITHOLDERS WILL HAVE NO RIGHT TO ENFORCE OBLIGATIONS OF OUR GENERAL PARTNER AND ITS AFFILIATES UNDER AGREEMENTS WITH US. Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor. 121 CONTRACTS BETWEEN US, ON THE ONE HAND, AND OUR GENERAL PARTNER AND ITS AFFILIATES, ON THE OTHER, WILL NOT BE THE RESULT OF ARM'S-LENGTH NEGOTIATIONS. The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are or will be the result of arm's-length negotiations. All of these transactions entered into after the sale of the common units offered in this offering are to be on terms that are fair and reasonable to us. Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There will not be any obligation of our general partner and its affiliates to enter into any contracts of this kind. COMMON UNITS ARE SUBJECT TO OUR GENERAL PARTNER'S LIMITED CALL RIGHT. Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. If we do not issue any equity securities prior to the expiration of the subordination period, upon the conversion of subordinated units into common units at the end of the subordination period, our general partner and its affiliates will own 80.2% of our outstanding common units and will be able to exercise this call right. For a description of this right, please read "The Partnership Agreement -- Limited Call Right." WE MAY NOT CHOOSE TO RETAIN SEPARATE COUNSEL FOR OURSELVES OR FOR THE HOLDERS OF COMMON UNITS. The attorneys, independent auditors and others who have performed services for us regarding the offering have been retained by our general partner, its affiliates and us and may continue to be retained by our general partner, its affiliates and us after the offering. Attorneys, independent auditors and others who will perform services for us in the future will be selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, after the sale of the common units offered in this prospectus, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties. OUR GENERAL PARTNER'S AFFILIATES MAY COMPETE WITH US. The partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement and in the omnibus agreement, affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us. Please read "Certain Relationships and Related Transactions -- Omnibus Agreement." FIDUCIARY RESPONSIBILITIES Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, 122 provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by a general partner to limited partners and the partnership. In order to induce our general partner to manage our business, the partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner to take into account the interests of parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because GP Natural Resource Partners LLC's directors have fiduciary duties to manage our general partner in a manner beneficial both to its owners as well as to you. Without these modifications, the general partner's ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit the general partner by enabling it to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us as described above. These modifications represent a detriment to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners: State-law fiduciary duty standards..................... Fiduciary duties are generally considered to include an obligation to act with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present. The Delaware Act generally provides that a limited partner may institute legal action on behalf of the limited partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. Partnership agreement modified standards..................... The partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, the partnership agreement permits our general partner to make a number of decisions in its "sole discretion." This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Other provisions of the partnership agreement provide that our general partner's actions must be made in its reasonable discretion. These standards reduce the obligations to which our general partner would otherwise be held. 123 The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be "fair and reasonable" to us under the factors previously set forth. In determining whether a transaction or resolution is "fair and reasonable" our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner will not constitute a breach of its fiduciary duty. These standards reduce the obligations to which our general partner would otherwise be held. In addition to the other more specific provisions limiting the obligations of our general partner, the partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith. Rights and remedies of unitholders................... The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions could include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person. We are required to indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. This indemnification is required if our general partner or any of these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests. Indemnification is also required for criminal proceedings if our general partner or these other persons had no reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. If you have questions regarding the fiduciary duties of our general partner, you should consult with your own counsel. Please read "The Partnership Agreement -- Indemnification." 124 SELLING UNITHOLDER Arch Coal is selling 1,901,250 common units in the initial public offering. Arch Coal will sell an additional 285,187 common units if the underwriters exercise the over-allotment option in full. Please read "Security Ownership of Certain Beneficial Owners and Management." 125 DESCRIPTION OF THE COMMON UNITS THE UNITS The common units and the subordinated units represent limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section, "Cash Distribution Policy" and "Description of Subordinated Units." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement." TRANSFER AGENT AND REGISTRAR Duties. American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following fees that will be paid by unitholders: - surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges; - special charges for services requested by a holder of a common unit; and - other similar fees or charges. There will be no charge to holders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity. Resignation or Removal. The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner is authorized to act as the transfer agent and registrar until a successor is appointed. TRANSFER OF COMMON UNITS The transfer of the common units to persons who purchase directly from the underwriters will be accomplished through the completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application. The form of transfer application is set forth as Appendix B to this prospectus and is also set forth on the reverse side of the certificates representing units. By executing and delivering a transfer application, the transferee of common units: - becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner; - automatically requests admission as a substituted limited partner in our partnership; - agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; - represents that the transferee has the capacity, power and authority to enter into the partnership agreement; - grants powers of attorney to officers of the general partner and any liquidator of our partnership as specified in the partnership agreement; and - makes the consents and waivers contained in the partnership agreement. 126 An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of th