UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

 

 

 

Commission file number: 1-31465

 

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

 

 

(713) 751-7507

(Registrant’s Telephone Number, Including Area Code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to Section 12(g) of the Act:

None.

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer

o Large Accelerated Filer     þ Accelerated Filer     o Non-accelerated Filer

 

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2)  Yes o     No þ

 

The aggregate market value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they were affiliates of the registrant) was approximately $609.0 million on June 30, 2005 based on a price of $57.99 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date. The Subordinated Units were not publicly traded on June 30, 2005.

 

As of February 27, 2006, there were 16,825,307 Common Units outstanding and 8,515,228 Subordinated Units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE.

None.

 

 

TABLE OF CONTENTS

 

 

Forward-Looking Statements

 

Statements included in this Form 10-K are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements.

 

Such forward-looking statements include, among other things, statements regarding capital expenditures, acquisitions and dispositions, expected commencement dates of coal mining, projected quantities of future coal production by our lessees producing coal from our reserves, projected demand or supply for coal that will affect sales levels, prices and royalties realized by us.

 

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

 

You should not put undue reliance on any forward-looking statements. Please read “Item 1A. Risk Factors” for important factors that could cause our actual results of operations or our actual financial condition to differ.

 

Natural Resource Partners L.P. is a limited partnership formed in April 2002, and we completed our initial public offering in October 2002. We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2005, we owned or controlled approximately two billion tons of proven and probable coal reserves in eleven states. We do not operate any mines, but lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. Our lessees are generally required to make payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, in addition to a minimum payment. As of December 31, 2005, our reserves were subject to 176 leases with 67 lessees. In 2005, our lessees produced 53.6 million tons of coal from our properties and our coal royalty revenues were $142.1 million.

 

Partnership Structure and Management

 

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through a wholly owned operating company, NRP (Operating) LLC. NRP (GP) LP, our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on our behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson is entitled to nominate all seven of the directors, three of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC.

 

Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation and Great Northern Properties Limited Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the WPP Group. Mr. Robertson owns the general partner of Western Pocahontas Properties 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.

 

The senior executives and other officers who manage the WPP Group assets also manage us. They are employees of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation, a company controlled by Mr. Robertson, and they allocate varying percentages of their time to managing our operations. Neither our general partner, GP Natural Resource Partners LLC, nor any of their affiliates receive any management fee or other compensation in connection with the management of our business, but they are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.

 

Our operations headquarters are located at P.O. Box 2827, 1035 Third Avenue, Suite 300, Huntington, West Virginia 25727 and the telephone number is (304) 522-5757. Our principal executive offices are located at 601 Jefferson Street, Suite 3600, Houston, Texas 77002 and our phone number is (713) 751-7507.

 

Coal Royalty Business

 

Coal royalty businesses are principally engaged in the business of owning and managing coal reserves. As an owner of coal reserves, we typically are not responsible for operating mines but instead enter into leases with 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 typical lease has a 5- to 10-year base term, with the lessee having an option to extend the lease for additional terms. Leases often include the right to renegotiate rents and royalties for the extended term.

Under our standard lease, third-party lessees calculate royalty and wheelage payments due us and are required to report tons of coal removed or hauled across our property as well as the sales prices of coal. Therefore, to a great extent, amounts reported as royalty and wheelage revenue are based upon the reports of our lessees. If permitted by the terms of the lease, we periodically audit this information by examining certain records and internal reports of our lessees, and we perform periodic mine inspections to verify that the information that has been submitted to us is accurate. Our audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to us and the actual results from each property. Our audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the royalty or wheelage revenue was initially recorded.

 

Coal royalty revenues are affected by changes in coal prices, lessees’ supply contracts and, to a lesser extent, fluctuations in the spot market prices for coal. The prevailing price for coal depends on a number of factors, including the supply-demand relationship, the price and availability of alternative fuels, global economic conditions and governmental regulations. In addition to their royalty obligation, our lessees are often subject to pre-established minimum monthly, quarterly or annual payments. These minimum rentals reflect amounts we are entitled to receive even if no mining activity occurred during the period. Minimum rentals are usually credited against future royalties that are earned when coal production commences.

 

Because we do not operate any mines, we do not bear ordinary operating costs and have limited direct exposure to environmental, permitting and labor risks. As operators, our lessees are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. In addition, the lessees generally bear all labor-related risks, including health care legacy costs, black lung benefits and workmen’s compensation costs, associated with operating the mines. We typically pay property taxes and then are reimbursed by the lessee for the taxes on the leased property, pursuant to the terms of the lease.

 

Our business is not seasonal, although at times severe weather can cause a short-term decrease in coal production by our lessees due to the weather’s negative impact on production and transportation.

 

Acquisitions in 2005

 

AFG.  On November 21, 2005, we completed the acquisition of 179 million tons of coal reserves in Ohio and Pennsylvania for $29 million.

 

Area F/Lexington.  In two separate transactions on September 26, 2005, we acquired approximately 25 million tons of owned coal reserves and an overriding royalty on approximately 14 million tons of leased coal reserves in Randolph, Upshur and Barbour Counties in north central West Virginia for $13.5 million.

 

Dolphin.  On September 22, 2005, we acquired a coal preparation plant and rail load-out facility in Greenbrier County, West Virginia for $6 million. We do not operate the preparation plant but receive a fee for coal processed through it. The facilities primarily process coal produced from our Plum Creek properties.

 

Williamson Development (formerly Steelhead).  On June 1, 2005, we signed a definitive agreement to purchase interests in approximately 144 million tons in the Illinois Basin for $105 million in three separate transactions. Ultimately, we will acquire approximately 60% of the reserves in fee and will receive an override on the remaining tons. On July 11, 2005, we closed the first of the three transactions for $35 million. The acquisition included approximately 47.5 million tons, of which approximately 75% are owned in fee. We received an override on the remaining tons. On January 20, 2006, we closed the second phase of this transaction for $35 million. We expect to close on the third and final phase in mid-2006.

 

Plum Creek.  On March 3, 2005, we completed an acquisition of coal reserves from Plum Creek Timber Company, Inc. for $21.25 million. This property consists of approximately 85 million tons of coal reserves located on approximately 175,000 acres in Virginia, West Virginia and Kentucky.

Coal Royalty Revenues, Reserves and Production

 

The following table sets forth coal royalty revenues and average coal royalty revenue per ton from the properties that we owned or controlled for the years ending December 31, 2005, 2004 and 2003. Coal royalty revenues were generated from the properties in each of the areas as follows:

 

 

The following table sets forth production data and reserve information for the properties that we own or control for the years ending December 31, 2005, 2004, and 2003. All of the reserves reported below are recoverable reserves as determined by Industry Guide 7. In excess of 90% of the reserves listed below are currently leased to third parties. Coal production data and reserve information for the properties in each of the areas is as follows:

 

Production and Reserves

 

 

We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is coal which meets the standards of Phase II of the Clean Air Act and is that portion of low sulfur coal that, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu. As of December 31, 2005, approximately 35% of our reserves were compliance coal. Unless otherwise indicated, we present the quality of the coal throughout this Form 10-K on an as-received basis, which assumes 6% moisture for Appalachian reserves, 12% moisture for Illinois Basin reserves and 25% moisture for Northern Powder River Basin reserves. We own both steam and metallurgical coal reserves in Northern, Central and Southern

Appalachia, and we own steam coal reserves in the Illinois Basin and the Northern Powder River Basin. In 2005, approximately 31% of the coal royalty revenues from our properties was from metallurgical coal.

 

The following table sets forth our estimate of the sulfur content, the typical quality of our coal reserves and the type of coal in each area as of December 31, 2005.

 

Sulfur Content, Typical Quality and Type of Coal

 

 

 

 

We base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers. This information is periodically reviewed by third party consultants. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

 

 

As a result, actual coal tonnage recovered from identified reserve areas or properties may vary from estimates or may cause our estimates to change from time to time. Any inaccuracy in the estimates related to our reserves could result in decreased royalties from lower than expected production by our lessees.

 

Oil, Gas and Timber Properties

 

For the year ended December 31, 2005, we derived less than 2% of our total revenues from oil, gas and timber, which are located in Kentucky, Virginia and Tennessee. We do not own the oil, gas or timber rights on the vast majority of the properties.

Significant Customers

 

We have three lessees who each provided more than 10% of our total revenue in 2005: Alpha Natural Resources, Inc., Arch Coal, Inc. and PinnOak Resources LLC. Each of these companies has several different mines on our properties. While the loss of any one of these lessees would have a material adverse effect on us, we do not believe that the loss of any single mine would have a material adverse effect on us.

 

Competition

 

We face significant competition from other land companies and from coal producers in purchasing coal reserves and royalty producing properties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation since 1976. The top ten producers have increased their share of total domestic coal production from 38% in 1976 to 65% in 2004. This consolidation has led to a number of our lessees’ parent companies having significantly larger financial and operating resources than their competitors. Our lessees compete with both large and small producers nationwide on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity and steel, as well as environmental and government regulations, technological developments and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, oil and hydroelectric power.

 

Regulation

 

The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:

 

 

In addition, the electricity generation industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for coal. New legislation or regulations may be adopted or enforcement of existing laws could change, either of which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal. Potential regulation 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. While we expect the current regulatory and legislative environment to add significantly to our lessees’ costs and to adversely impact their productivity, we do not at this time expect that future compliance costs will have a material adverse effect on us, our unitholders or our 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 substantially increases the cost of coal mining for all domestic coal producers.

 

Specific Regulatory and Litigation Matters

 

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 similar state and local laws.

 

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 is complete. 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 reclaim mines closed before 1977. Since our lessees are responsible for these obligations and any related liabilities, we do not accrue the estimated costs of reclamation or 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 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. We believe our lessees are generally in compliance with all operational, reclamation and closure requirements under their SMCRA permits.

 

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 into 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. In Ohio Valley Environmental Coalition v. Whitman, the court vacated the EPA’s approval of West Virginia’s antidegradation implementation policy that exempted current holders of National Pollutant Discharge Elimination System (NPDES) permits and Section 404 permits, among other parties, from the antidegradation-review process. On March 29, 2004, EPA Region III sent a letter to the West Virginia Department of Environmental Protection that approved portions of the state’s antidegradation program, denied approval of portions pending further study, and recommended removal of certain language in the state’s regulations. The West Virginia Department of Environmental Protection is proceeding with a review. Our lessees are current NPDES or Section 404 permit holders that had been exempt from antidegradation review under the former policy. With exemptions not in place, our lessees that discharge into waters that have been designated as high quality by the state may experience delays in the issuance or reissuance of Clean Water Act

permits, or these permits may be denied. Delay in issuance of or denial of these permits increases the costs of coal production and could potentially reduce our royalty revenues.

 

Massey Energy Settlement.  In January 2006, Massey Energy agreed to a settlement with the West Virginia Department of Environmental Protection relating to a number of lawsuits and enforcement actions against Massey and its subsidiaries. In connection with the settlement, Marfork Coal, a Massey subsidiary that mines coal on our Dorothy-Sarita and Eunice properties, agreed to shut down its operations for a total of six days. In 2005, we received $4.7 million in coal royalty revenues from Marfork Coal, and we do not expect this settlement to have a material impact on our coal royalty revenues.

 

Mine Health and Safety Laws.  Stringent safety and health standards have been imposed on the coal mining industry by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 also 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 black lung and to some survivors of miners who die 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.

 

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 to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standards.

 

Numerous legal and regulatory actions have been initiated over the years under the Clean Air Act, the outcome of which could adversely affect coal mining and coal-fired power plants. In January 2005, legislation was re-introduced in Congress outlining the Bush administration’s Clear Skies Initiative, which calls for dramatic decreases in sulfur, nitrogen oxide, and mercury emissions from power plants. If emissions standards from power plants are required to be lowered under the act, it could result in a decrease in coal demand.

 

If Clear Skies is not passed, EPA has announced an intention to take alternative action and finalize the Clean Air Interstate Rule (“CAIR”), and a related rule to reduce mercury emissions, under the existing Clean Air Act. The CAIR would mandate reductions in sulfur dioxide and nitrogen oxides in 29 states and the District of Columbia while the mercury rule would require mercury emissions reductions on a national basis. EPA is seeking to lower mercury emissions at new and existing sources by requiring the use of Maximum Achievable Control Technology (“MACT”), or, in the alternative, by implementing a nationwide “cap and trade” program. Should either or both of these proposed rules become final, additional costs may be associated with operating coal-fired power generation facilities that may make coal a less attractive fuel source.

 

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. 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.

 

In March 2002, the Army Corps of Engineers issued Nationwide Permit 21 under Section 404 to allow mining companies to discharge into fills without obtaining individual permits under the Clean Water Act. The legality of that permitting scheme was challenged in a lawsuit filed in October 2003 by the Ohio Valley Environmental Coalition and several other citizens groups. This lawsuit, Ohio Valley Environmental Coalition v. Bulen, was the latest in a series of lawsuits filed in the United States District Court for the Southern District of West Virginia by citizens groups challenging the legality of various aspects of the regulatory scheme for the permitting of surface coal mining, especially mountaintop removal coal mining and valley fills. Although the first two lawsuits were successful at the district court level, the Fourth Circuit Court of Appeals overturned both decisions.

 

In Ohio Valley Environmental Coalition v. Bulen, plaintiffs alleged that a nationwide permit cannot lawfully be issued under Section 404 for the surface mining of coal and that the Corps of Engineers failed to comply with the requirements of the National Environmental Policy Act in the adoption of Nationwide Permit 21. In July 2004, the district court enjoined the Corps of Engineers from issuing future authorizations under Nationwide Permit 21in the Southern District of West Virginia. With respect to the eleven specific mining sites challenged by the plaintiffs, the Corps of Engineers was ordered to suspend those authorizations for valley fills and surface impoundments on which construction had not commenced as of July 8, 2004. In a subsequent order in August 2004, the district court clarified that the Corps of Engineers must suspend all existing authorizations under Nationwide Permit 21 for valley fills and surface impoundments in the Southern District of West Virginia on which construction had not commenced as of July 8, 2004. In November 2005, the Fourth Circuit Court of Appeals overturned the decision of the district court, finding that the Corps of Engineers had not violated the Clean Water Act in its issuance and application of Nationwide Permit 21. The Fourth Circuit remanded the case back to the district court.

 

In January 2005, a lawsuit was filed in Eastern District of Kentucky on similar grounds challenging the legality of Nationwide Permit 21. In March 2005, the plaintiffs filed a motion for summary judgment requesting the court to (1) issue a declaratory judgment that Nationwide Permit 21 violates Section 404 of the Clean Water Act and (2) issue an injunction prohibiting the Corps from issuing further authorizations pursuant to Nationwide Permit 21 in Kentucky. The motion also requested the court to suspend those authorizations for valley fills on which the placement of mining spoil in streams had not commenced as of the date of filing of the motion. In June 2005, the judge transferred the case from the Lexington Division to the Pikeville Division, and oral arguments have recently concluded. We will continue to monitor this litigation and its impact on the development of our coal reserves.

 

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.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for restoring the mined property to its prior condition, productive use or other permitted condition upon the completion of mining operations. 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 our reserves that are currently planned to be mined over the next five years. Our lessees are in the planning phase for obtaining permits for the reserves planned to be mined over the subsequent five years. We cannot assure you, however, that they will not experience difficulty in obtaining mining permits in the future.

 

As a consequence of potential future legislation and administrative regulations that may emphasize the protection of the environment, 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.

 

Framework Convention on Global Climate Change.  The United States and more than 160 other nations are signatories to the 1992 United Nations Framework Convention on Global Climate Change that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. In December 1997, in Kyoto, Japan, the signatories to the convention established a potentially binding set of emissions targets for developed nations. In March 2001, the Bush Administration withdrew its support for the Kyoto Protocol, and the United States is not subject to its requirements. However, other countries have ratified the protocol, which will enter into force and require developing nations subject to it to reduce greenhouse gas emissions over a five-year period from 2008 to 2012. As an alternative to the Kyoto Protocol, in February 2002, the Bush administration announced a new approach to climate change, proposing voluntary actions to reduce the greenhouse gas intensity of the U.S. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The Bush Administration continues to pursue this voluntary approach. Moreover, 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. Additionally, states, such as New Jersey and Maine, independently regulate emissions of certain greenhouse gases. 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.

 

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 on lands that we currently own or have previously owned, 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.

 

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 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 will not receive protected status under the Endangered Species Act or that currently protected species will 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 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.

 

Employees and Labor Relations

 

We do not have any employees. To carry out our operations, affiliates of our general partner employ approximately 47 employees who directly support our operations. None of these employees are subject to a collective bargaining agreement. Some of the employees of our lessees and sub-lessees are subject to collective bargaining agreements.

 

Segment Information

 

Pursuant to SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information,” we are not required to disclose separate segment information because the materiality of timber and oil and gas do not meet the test for segment disclosure.

 

Website Access To Company Reports

 

Our internet address is www.nrplp.com. We make available free of charge on or through our internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Also included on our website are our “Code of Business Conduct and Ethics” adopted by our Board of Directors and the charters for our Audit Committee, Conflicts Committee and Compensation, Nominating and Governance Committee. Also, copies of our annual report, the Code of Business Conduct and Ethics, our Corporate Governance Guidelines and our committee charters will be made available upon written request.

 

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:

 

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:

 

 

You should also be aware that our ability to pay quarterly distributions depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.

 

A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our reserves.

 

The prices our lessees receive for their coal depend upon factors beyond their or our control, including:

 

 

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.

 

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:

 

 

 

These conditions may increase our lessees’ cost of mining and delay or halt production at particular mines for varying lengths of time or permanently. Any interruptions to the production of coal from our reserves may reduce our coal royalty revenues.

 

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.

 

If reductions in production by these operators 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 materially reduce our coal royalty revenues.

 

We may not be able to terminate our leases, and we may experience delays and be unable to replace lessees that do not make royalty payments.

 

A failure on the part of one of our lessees to make coal royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.

 

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:

 

 

 

Adverse developments in the coal industry could reduce our coal royalty revenues and, due to our lack of asset diversification, could substantially reduce our total 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 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 2005, approximately 27% of the coal production from our properties was metallurgical coal. The steel industry has increasingly relied on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that our lessees mine could continue to decrease. Additionally, since the amount of steel that is produced is tied to global economic conditions, a decline in those conditions could result in the decline of steel, coke and coal production. Since metallurgical coal is priced higher than steam coal, some mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If these mines are unable to sell metallurgical coal, these mines may not be economically viable and may close.

 

We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves or obtain other mineral reserves through acquisitions.

 

Because our reserves decline as our lessees mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves or other mineral reserves that are economically recoverable. If we are unable to replace or increase our coal reserves or acquire other mineral reserves on acceptable terms, our royalty revenues will decline as our reserves are depleted. In addition, if we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our royalty revenues may decline and we could experience a material adverse effect on our business, financial condition or results of operations. If we acquire additional reserves, there is a possibility that any acquisition could be dilutive to our earnings and reduce our ability to make distributions to unitholders. Any debt we incur to finance an acquisition may also reduce our ability to make distributions to unitholders. Our ability to make acquisitions in the future also could be limited by restrictions under our existing or future debt agreements, competition from other mineral companies for attractive properties or the lack of suitable acquisition candidates.

 

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 new power plants will be built to produce electricity. Some of these new power plants will be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the federal Clean Air Act may result in more electric power generators shifting from coal to natural-gas-fired power plants.

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 from the Appalachian region and the Illinois Basin. This competition could result in a decrease in market share for our lessees operating in these regions and a decrease in our coal royalty revenues.

 

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. This decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on coal prices.

 

Conversely, the amount of coal imported into the United States over the last few years has increased. This increase is mostly due to the economic and environmental advantages of some imported coal. A continued increase in imported coal could result in less of our coal being mined and sold and reduce our coal royalty revenues. Additionally, lower priced imported coal could result in lower coal prices that would reduce our coal royalty revenues.

 

Lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.

 

Coal supply contracts do not generally require operators to satisfy their obligations to their customers with coal mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer coal specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower coal royalty revenues.

 

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

 

Transportation costs represent a significant portion of the total cost of coal for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from coal producers in other parts of the country.

 

Our lessees depend upon railroads, barges, trucks and beltlines to deliver coal to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair the ability of our lessees to supply coal to their customers. Our lessees’ transportation providers may face difficulties in the future that may impair the ability of our lessees to supply coal to their customers, resulting in decreased coal royalty revenues to us.

 

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:

 

 

Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on our coal reserve data that is included in this report.

 

Our lessees’ work forces could become increasingly unionized in the future.

 

Some of the 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 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.

 

Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties.

 

Our lessees may incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, including regulations and governmental enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our lessees’ operations. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our lessees are pursued for these sanctions, costs and liabilities, their mining operations and, as a result, our coal royalty revenues could be adversely affected.

 

New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements and the protection of endangered species, could further regulate or tax the coal industry and may also require our lessees to change their operations significantly to incur increased costs or to obtain new or different permits, any of which could decrease our coal royalty revenues.

 

A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

 

We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of coal royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.

 

None.

 

 

Major Coal Properties

 

The following is a summary of our major coal properties in each coal producing region:

 

Northern Appalachia

 

Sincell.  The Sincell property is located in Garrett County, Maryland. In 2005, 2.6 million tons were produced from this property. We lease this property to Mettiki Coal, LLC, a subsidiary of Alliance Resource Partners L.P. Coal is produced from an underground mine and a surface mine. It is transported by belt or truck to a preparation plant operated by the lessee. Coal is shipped primarily by truck to the Mount Storm power plant of Dominion Power.

 

AFG-Southwest PA.  The AFG property is located in Washington County, Pennsylvania. We acquired this property in November 2005. In 2005, 1.5 million tons were produced from this property. We lease this property to Conrhein Coal Company, a subsidiary of Consol Energy. Coal is produced from an underground mine and is transported by belt to a preparation plant operated by the lessee. Coal is shipped by both the CSX and Norfolk Southern railways to utility customers, such as American Electric Power and Allegheny Energy.

 

The map on the following page shows the location of our properties in Northern Appalachia.

Central Appalachia

 

VICC/Alpha.  The VICC/Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2005, 6.5 million tons were produced from this property. We lease this property to Alpha Land and Reserves, LLC. Production comes from both underground and surface mines and is trucked to one of four preparation plants. Coal is shipped via both the CSX and Norfolk Southern railroads to utility and metallurgical customers. Major customers include American Electric Power, Southern Company, Tennessee Valley Authority, VEPCO and U.S. Steel.

 

Lynch.  The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2005, 5.1 million tons were produced from this property. We primarily lease the property to Resource Development, LLC, an independent coal producer. Production comes from both underground and surface mines. Coal is transported by truck to a preparation plant on the property and is shipped primarily on the CSX railroad to utility customers such as Georgia Power and Orlando Utilities.

 

Pinnacle Property.  The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. This property is leased to PinnOak Resources, LLC. In 2005, 2.9 million tons were produced from this property. Metallurgical coal is produced from two underground mines and transported by belt or truck to a preparation plant operated by the lessee. Coal is shipped via the Norfolk Southern railroad to customers such as U.S. Steel, National Steel, and is exported to a number of customers located in Europe.

 

Lone Mountain.  The Lone Mountain property is located in Harlan County, Kentucky. In 2005, 2.6 million tons were produced from this property. We lease the property to Ark Land Company, a subsidiary of publicly held Arch Coal, Inc. Production comes from underground mines and is transported primarily by beltline to a preparation plant on adjacent property and shipped on the Norfolk Southern or CSX railroads to utility customers such as Georgia Power and the Tennessee Valley Authority.

 

Eunice.  The Eunice property is located in Raleigh and Boone Counties, West Virginia. In 2005, 2.6 million tons were produced from this property. 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, a surface operation and an underground longwall mine. These operations extend onto adjacent reserves and will also eventually extend onto a portion of our nearby Y&O property. Coal production from this operation is generally transported by beltline and processed at two preparation plants located off the property. The preparation plants ship 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.

 

VICC/Kentucky Land.  The VICC/Kentucky Land property is located primarily in Perry, Leslie and Pike Counties, Kentucky. In 2005, 2.5 million tons were produced from this property. Coal is produced from a number of lessees from both underground and surface mines. Coal is shipped primarily by truck but also on the CSX and Norfolk Southern railroads to customers such as Southern Company, Tennessee Valley Authority, and American Electric Power.

 

The map on the following page shows the location of our properties in Central Appalachia.

Southern Appalachia

 

BLC Properties.  The BLC properties are located in Kentucky, Tennessee, and Alabama. In 2005, 3.8 million tons were produced from these properties. We lease this property to a number of operators including Appolo Fuels Inc., Bell County Coal Corporation and Kopper-Glo Fuels. Production comes from both underground and surface mines and is trucked to preparation plants and loading facilities operated by our lessees. Coal is transported by truck and is shipped via both CSX and Norfolk & Southern railroads to utility and industrial customers. Major customers include Southern Company, South Carolina Electric & Gas, and numerous medium and small industrial customers.

 

The map below shows the location of our properties in Southern Appalachia.

 

Illinois Basin

 

Hocking-Wolford/Cummings.  The Hocking-Wolford property and the Cummings property are both located in Sullivan County, Indiana. In 2005, 1.4 million tons were produced from our property. Both properties are under common lease to Black Beauty Coal Company, an affiliate of publicly held Peabody Energy. Production is currently from a surface mine, and coal is shipped by truck and railroad to customers such as Public Service of Indiana and Indianapolis Power and Light.

 

Williamson Development.  On June 1, 2005, we signed a definitive agreement to purchase interests in approximately 144 million tons in the Illinois Basin in three separate transactions. Ultimately, we will acquire approximately 60% of the reserves in fee and will receive an override on the remaining tons. We closed the first of the three transactions on July 11, 2005, and on January 20, 2006, we closed the second phase of this transaction. We expect to close on the third and final phase in mid-2006. We expect production to begin in the second half of 2006, with significant production starting in 2007.

 

The map below shows the location of our properties in Illinois Basin.

 

 

Northern Powder River Basin

 

Western Energy.  The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2005, 5.8 million tons were produced from our property. Western Energy Company, a subsidiary of publicly held Westmoreland Coal Company, has two coal leases on the property. Western Energy produces coal by surface dragline mining, and the coal is transported by either truck or beltline to the four-unit 2,200-megawatt Colstrip generation station located at the mine mouth and by the Burlington Northern Santa Fe railroad to Minnesota Power. A small amount of coal is transported by truck to other customers.

 

The map below shows the location of our properties in Northern Powder River Basin.

 

 

Title to Property

 

Of the approximately two billion tons of proven and probable coal reserves to which we had rights as of December 31, 2005, we owned approximately 99% of the reserves in fee. We lease approximately 18.5 million tons, or 1% of our reserves, from unaffiliated third parties. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operations of our business.

 

For most of our properties, the surface, oil and gas and mineral or coal estates are owned by different entities. Some of those entities are our affiliates. State law and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the existence of the severed estates will materially impede development of the minerals on our properties.

 

In February 2006, NRP was dismissed from the pending flood litigation trial in West Virginia that we had disclosed in previous public filings. We are involved, from time to time, in various other legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, we believe these claims will not have a material effect on our financial position, liquidity or operations.

 

None.

 

Our common units are listed and traded on the New York Stock Exchange (NYSE) under the symbol “NRP”. As of February 9, 2006, there were an estimated 20,000 beneficial owners of our common units. The computation of the approximate number of unitholders is based upon a broker survey.

 

The following table sets forth the high and low sales prices per common unit, as reported on the New York Stock Exchange Composite Transaction Tape from January 1, 2004 to December 31, 2005, and the quarterly cash distribution declared and paid with respect to each quarter per common unit.

 

NRP

 

 

In addition to common units, we have also issued subordinated units that are listed and traded on the NYSE under the symbol “NSP”. As of February 9, 2006, there were an estimated 3,900 beneficial owners of our subordinated units. The computation of the approximate number of unitholders is based upon a broker survey. The subordinated units were issued as part of our initial public offering in October 2002 and receive a quarterly distribution only after sufficient funds have been paid to the common units, as described below. The subordinated units were held privately until August 2005, when a large holder of subordinated units sold 4,200,000 of its subordinated units in a public offering. Subsequently, this unitholder sold the remainder of its subordinated units in several block trades in December 2005. Other than its subordinated units that converted into common units in November 2005 as described below, the WPP Group still owns all of the subordinated units it received in the initial public offering.

 

The following table sets forth the high and low sales prices per subordinated unit, as reported on the New York Stock Exchange Composite Transaction Tape from August 10, 2005, the first day of trading, to December 31, 2005, and the quarterly cash distribution declared and paid with respect to each quarter per subordinated unit. In addition to the data in the table, prior to going public, the subordinated units received the same distributions every quarter as the common units.

 

NSP

 

 

During the subordination period, the holders of our common units are entitled to receive a minimum quarterly distribution of $0.5125 per unit prior to any distribution of available cash to holders of our

subordinated units. The subordination period is defined generally as the period that will end on the first day of any quarter beginning after September 30, 2007 if (1) we have distributed at least the minimum quarterly distribution on all outstanding units in each of the immediately preceding three consecutive, non-overlapping four-quarter periods and (2) our adjusted operating surplus, as defined in our partnership agreement, during such periods equals or exceeds the amount that would have been sufficient to enable us to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2% general partner interest during those periods. In addition, 25% of the initial outstanding subordinated units may convert to common units on a one-for-one basis after September 30, 2006, if we meet the tests set forth in our partnership agreement. If the subordination period ends, the common units will no longer be entitled to arrearages, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units may be converted into common units.

 

On November 14, 2005, 25% of the subordinated units converted into common units. Providing that the minimum quarterly distribution has been earned and paid to both the common and subordinated units for the preceding 12 quarters, the remaining NSP subordinated units will convert into NRP common units automatically on the following schedule:

 

 

Following the conversion in mid-November 2007, NSP units will no longer exist and all subordinated units will have been converted into NRP units.

 

Our general partner and affiliates of our general partner are entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds the specified target levels shown below:

 

Percentage Allocations of Available Cash From Operating Surplus

 

 

We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash” as that term is defined in our partnership agreement. The amount of available cash may be greater than or less than the minimum quarterly distribution. In general, we intend to increase our cash distributions in the future assuming we are able to increase our “available cash” from operations and through acquisitions, provided there is no adverse change in operations, economic conditions and other factors. However, we cannot guarantee that future distributions will continue at such levels.

 

SELECTED HISTORICAL FINANCIAL DATA

 

The following tables show selected historical financial data for Natural Resource Partners L.P. and our predecessors (Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and the Arch Coal Contributed Properties, collectively known as predecessors), in each case for the periods and as of the dates indicated. We derived the selected historical financial data for Natural Resource Partners L.P. as of December 31, 2005, 2004, 2003 and 2002, and for the years ended December 31, 2005, 2004 and 2003 and the period from commencement of operations (October 17, 2002) through December 31, 2002 from the audited financial statements of Natural Resource Partners L.P. We derived the selected historical financial data for the members of the WPP Group (see page 2) for the period from January 1 through October 16, 2002 and as of and for the year ended December 31, 2001 from the audited financial statements of the WPP Group, and we derived the selected historical financial data for the Arch Coal Contributed Properties for the period from January 1 through October 16, 2002 and as of and for the year ended December 31, 2001 from the audited financial statements of the Arch Coal Contributed Properties.

 

We derived the information in the following tables from, and the information should be read together with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in Item 8, “Financial Statements and Supplementary Data.” The tables should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” While substantially all of the producing coal-related assets and operations of the WPP Group were contributed to us, some assets and liabilities were retained by the WPP Group.

NATURAL RESOURCE PARTNERS L.P.

 

 

 

WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP

 

 

 

GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP

 

 

 

NEW GAULEY COAL CORPORATION

 

 

 

ARCH COAL CONTRIBUTED PROPERTIES

 

 

 

 

The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing. For more detailed information regarding the basis of presentation for the following financial information, see the notes to the historical financial statements.

 

Executive Overview

 

We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. Coal produced from our properties is burned in electric power plants located east of the Mississippi River and in Montana and Minnesota. As of December 31, 2005, we owned or controlled approximately two billion tons of proven and probable coal reserves in eleven states. For the year ended December 31, 2005, approximately 61% of the coal produced from our properties came from underground mines and approximately 39% came from surface mines. As of December 31, 2005, approximately 57% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 35% of our reserves.

 

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. As of December 31, 2005, our reserves were subject to 176 leases with 67 lessees. For the year ended December 31, 2005, our lessees produced 53.6 million tons of coal generating $142.1 million in coal royalty revenues from our properties and our total revenue was $159.1 million.

 

Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Generally, our lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are recorded as deferred revenue, a liability on our balance sheet.

 

Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated sales departments. A significant portion of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. However, over the long term, our coal royalty revenues are affected by changes in the market price of coal.

 

Coal royalty revenues from our Appalachian properties represented 91% of our total coal royalty revenues for the year ended December 31, 2005, and thus a significant portion of our total revenue is dependent upon Appalachian coal prices. Coal prices are based on supply and demand, specific coal characteristics, economics of alternative fuel, and overall domestic and international economic conditions. Our lessees located in Appalachia have recently experienced a greater demand for coal, and coal prices for both metallurgical and steam coal for those producers increased during 2004 and 2005. Towards the end of the second quarter of 2004, our Appalachian lessees began to enter into new coal sales contracts at the higher prices. As their older contracts have continued to rollover during the last 15 months, we have received substantially higher royalties from our leases, and our revenue per ton from that region has increased to an average of $2.87 per ton for the year ended December 31, 2005 from an average of $2.34 per ton for the same period of 2004. However, because prices have generally stabilized over the last six months and our lessees will have fewer contracts that will rollover into substantially higher prices, we expect that our coal royalty revenue per ton will not continue to increase at this pace over the next year. In addition, in spite of the higher prices, most of our lessees have not appreciably increased production due to a number of constraints, including a shortage of labor, permitting issues and rail transportation problems. As a result, we believe that a larger percentage of our future revenue growth will come from acquisitions of new reserves.

For the year ended December 31, 2005, approximately 31% of our coal royalty revenues and 27% of the related production were from metallurgical coal, which was sold to steel companies in the eastern United States, South America, Europe and Asia. Prices of metallurgical coal have been substantially higher over the last two years and we expect them to remain at historically high levels in 2006 as well. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and seaborne export markets.

 

In addition to coal royalty revenues, we generated approximately 6% of our revenues for the years ended December 31, 2005 and 2004, respectively, from rentals; royalties on oil and gas and coalbed methane leases; timber; overriding royalty arrangements; and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

 

Under our partnership agreement, we are required to distribute all of our available cash each quarter. Because distributable cash flow is a significant liquidity metric that is an indicator of our ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to our partners, we view it as the most critical measure of our success as a company. Distributable cash flow is also the quantitative standard used in the investment community with respect to publicly traded partnerships.

 

Distributable cash flow represents cash flow from operations less actual principal payments and cash reserves set aside for scheduled principal payments on our senior notes. Although distributable cash flow is a “non-GAAP financial measure,” we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Distributable cash flow may not be calculated the same for NRP as for other companies. A reconciliation of distributable cash flow to net cash provided by operating activities is set forth below.

 

Reconciliation of GAAP “Net Cash Provided by Operating Activities”
to Non-GAAP “Distributable Cash Flow”

 

 

Acquisitions

 

2005 Acquisitions

 

AFG.  On November 21, 2005, we completed the acquisition of 179 million tons of coal reserves in Ohio and Pennsylvania for $29 million.

 

Area F/Lexington.  In two separate transactions on September 26, 2005, we acquired approximately 25 million tons of owned coal reserves and an overriding royalty on approximately 14 million tons of leased coal reserves in Randolph, Upshur and Barbour Counties in north central West Virginia for $13.5 million.

 

Dolphin.  On September 22, 2005, we acquired a coal preparation plant and rail load-out facility in Greenbrier County, West Virginia for $6 million. We do not operate the preparation plant but receive a fee for coal processed through it. The facilities primarily process coal produced from our Plum Creek properties.

 

Williamson Development (formerly Steelhead).  On June 1, 2005, we signed a definitive agreement to purchase interests in approximately 144 million tons in the Illinois Basin for $105 million in three separate transactions. Ultimately, we will acquire approximately 60% of the reserves in fee and will receive an override

on the remaining tons. On July 11, 2005, we closed the first of the three transactions for $35 million. On January 20, 2006, we closed the second phase of this transaction for $35 million. We expect to close on the third and final phase in mid-2006.

 

Plum Creek.  On March 3, 2005, we completed an acquisition of coal reserves from Plum Creek Timber Company, Inc. for $21.25 million. This property consists of approximately 85 million tons of coal reserves located on approximately 175,000 acres in Virginia, West Virginia and Kentucky.

 

2004 Acquisitions

 

Clinchfield.  In September 2004, we purchased a tract of coal reserves from Clinchfield Coal Company in Dickenson County, Virginia for $0.4 million. This property adjoins other property we own and represents approximately 0.8 million tons. We have subsequently combined this property with other properties under an existing lease to a subsidiary of Alpha Natural Resources.

 

Pardee Minerals.  In May 2004, we purchased a tract of coal reserves from Pardee Minerals LLC in Wise County, Virginia for $1.6 million. This property adjoins other property we own and represents approximately 1.0 million tons. As a part of this transaction, we took an assignment of a coal lease under which a subsidiary of Alpha Natural Resources is the lessee.

 

Appolo.  In February 2004, we purchased two tracts of property from Appolo Fuels, Inc. in Bell County, Kentucky for $2.5 million. This property adjoins the properties purchased in the BLC acquisition and represents approximately 2.5 million tons. As a part of this transaction, an older below market lease affecting approximately 2.5 million additional tons of adjacent reserves was renegotiated to current royalty rates.

 

BLC Properties.  In January 2004, we purchased all of the mineral interests of BLC Properties LLC for $73.0 million. This acquisition included coal, oil and gas and other mineral rights on approximately 270,000 acres that contain approximately 176 million tons of coal reserves. We lease these reserves to eight different lessees. The transaction also included oil and gas and other mineral rights on approximately 205,000 additional acres. The properties are located in Kentucky, Tennessee, West Virginia, Virginia, and Alabama. BLC retained a 35% non-participating royalty interest in the oil and gas and other mineral rights.

 

2003 Acquisitions

 

Eastern Kentucky Reserves.  In November 2003, we acquired coal reserves and related interests in eastern Kentucky from a number of private sellers for $18.8 million. The acquisition included approximately 21 million tons of coal reserves, an additional royalty interest in approximately 8 million tons of coal reserves on contiguous property, and the right to collect a wheelage fee on 10 million tons of coal. We lease some of these reserves to Appalachian Fuels.

 

PinnOak Resources.  In July 2003, we acquired approximately 79 million tons of coal reserves and an overriding royalty interest on additional coal reserves from subsidiaries of PinnOak Resources, LLC for $58.0 million. We lease these reserves to other subsidiaries of PinnOak Resources. PinnOak Resources produces low volatile metallurgical coal from these longwall mines and has onsite preparation plants. The properties consist of coal reserves located at two mine complexes: the Pinnacle mine in Pineville, West Virginia and the Oak Grove mine near Birmingham, Alabama.

 

Alpha Natural Resources Reserves.  In April 2003, we acquired approximately 295,000 mineral acres containing approximately 353 million tons of coal reserves from two subsidiaries of Alpha Natural Resources, LLC for $53.6 million. We leased most of these reserves to two Alpha subsidiaries and seven other operators. The properties are located in Virginia adjacent to the coal properties that we acquired from El Paso Corporation in December 2002, which are operated by another subsidiary of Alpha Natural Resources, LLC.

 

Alpha Natural Resources Royalty Interest.  In February 2003, we purchased an overriding royalty interest in the coal reserves that we purchased from El Paso Corporation in December 2002 from a subsidiary of Alpha Natural Resources LLC for $11.9 million.

Critical Accounting Policies

 

Coal Royalties.  We recognize coal royalty revenues on the basis of tons of coal sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are carried as deferred revenue, a liability on the balance sheet.

 

Timber Royalties.  We sell timber on a contract basis under which 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.

 

Oil and Gas Royalties.  We recognize oil and gas royalties on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on a percentage of the selling price. Some leases are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue and recognized either when the lessee recoups the minimum payments through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

 

Depreciation and Depletion.  We depreciate our plant and equipment on a straight line basis over the estimated useful life of the asset. We deplete 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 in those properties. We estimate proven and probable coal reserves with the assistance of third-party mining consultants, and we use estimation techniques and recoverability assumptions. Our estimates of coal reserves are updated periodically and may result in material adjustments to coal reserves and depletion rates that are recognized prospectively. Historical revisions have not been material. Timberlands are stated at cost less depletion. We determine the cost of the timber harvested based on the volume of timber harvested in relation to the amount of estimated net merchantable volume by geographic areas. We estimate our timber inventory using statistical information and data obtained from physical measurements and other information gathering techniques. We update these estimates annually, which may result in adjustments of timber volumes and depletion rates that are recognized prospectively. Changes in these estimates have no effect on our cash flow.

 

LTIP Awards and New Accounting Standards

 

Statement of Financial Accounting Standards No. 123R “Accounting for Stock-Based Compensation,” revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R, effective for the first quarter of 2006, requires us to recognize a cumulative effect of the accounting change at the date of adoption based on the difference between the fair value of the unvested awards and the intrinsic value recorded. Additionally, FAS 123R provides that grants after the effective date must be accounted for using the fair value method which will require us to estimate the fair value of the grant using an accepted method and charge the estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires that the fair value be recalculated at each reporting date over the service or vesting period of the grant. Use of the fair value method as compared with the intrinsic method, will not change the total expense to be reflected for a grant but it may impact the period in which expense is reflected by increasing expense in one period based upon the fair value calculation and lowering expense in a different period. We are in the process of evaluating the impact of FAS 123R and expect to adopt it in the first quarter of 2006 using the modified prospective method.

Results of Operations

 

Natural Resource Partners L.P.