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

 

 

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

 

The aggregate market value of the Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Units outstanding, for this purpose, as if they were affiliates of the registrant) was approximately $649.7 million for the Common Units and $225.9 million for the Subordinated Units on June 30, 2006 based on a price of $54.20 per unit for the Common Units and $50.94 per unit for the Subordinated Units. These prices are the respective closing prices of the Units as reported on the New York Stock Exchange on that date.

 

As of February 27, 2007, there were 25,976,795 Common Units outstanding, 5,676,817 Subordinated Units outstanding and 541,956 Class B Units outstanding. The Class B Units are not publicly traded.

 

DOCUMENTS INCORPORATED BY REFERENCE.

 

None.

 

Table of Contents

 

Forward-Looking Statements

 

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

 

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

 

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

 

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

 

Natural Resource Partners L.P. is a limited partnership formed in April 2002, and we completed our initial public offering in October 2002. We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2006, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves in eleven states. We do not operate any mines, but lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. Our lessees are generally required to make payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, in addition to minimum payments. As of December 31, 2006, our coal reserves were subject to 180 leases with 70 lessees. In 2006, our lessees produced 52.1 million tons of coal from our properties and our coal royalty revenues were $147.8 million.

 

In 2006 we added two new businesses: coal infrastructure and ownership of aggregate reserves that are leased to operators in exchange for royalty payments similar to our coal royalty business. Neither of these businesses currently contribute a large percentage of our total revenues, but we anticipate that we will grow these businesses in the future.

 

Partnership Structure and Management

 

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through a wholly owned operating company, NRP (Operating) LLC. NRP (GP) LP, our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on our behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Subject to the Investor Rights Agreement with Adena Minerals, LLC, Mr. Robertson is entitled to nominate nine directors, five of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals. Pending the appointment of an additional independent director by Adena, we currently have eight directors, four of whom are independent.

 

Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation and Great Northern Properties Limited Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the WPP Group. Mr. Robertson owns the general partner of Western Pocahontas Properties, 85% of the general partner of Great Northern Properties and is the Chairman, Chief Executive Officer and controlling stockholder of New Gauley Coal Corporation.

 

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

 

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

 

Coal Royalty Business

 

Coal royalty businesses are principally engaged in the business of owning and managing coal reserves. As an owner of coal reserves, we typically are not responsible for operating mines, but instead enter into leases with coal mine operators granting them the right to mine and sell coal reserves from our property in exchange for a royalty

payment. A typical lease has a 5- to 10-year base term, with the lessee having an option to extend the lease for additional terms. Leases often include the right to renegotiate rents and royalties for the extended term.

 

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

 

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

 

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

 

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

 

Recent Acquisitions

 

We are a growth-oriented company and have closed a number of accretive acquisitions over the last several years. Our most recent acquisitions are briefly described below.

 

2007 Acquisitions

 

Dingess-Rum.  On January 16, 2007, we acquired 92 million tons of coal reserves and approximately 33,700 acres of surface and timber in Logan, Clay and Nicholas Counties in West Virginia from Dingess-Rum Properties, Inc. As consideration for the acquisition, we issued 2,400,000 common units to Dingess-Rum in a private placement.

 

Cline.  On January 4, 2007, we acquired 49 million tons of coal reserves in Williamson County, Illinois and Mason County, West Virginia that are leased to affiliates of The Cline Group. In addition, we acquired transportation assets and related infrastructure at those mines. As consideration for the transaction we issued 3,913,080 common units and 541,956 Class B units in a private placement. Through its affiliate Adena Minerals, LLC, The Cline Group has also received a 22% interest in our general partner and in the incentive distribution rights of NRP in return for providing NRP with the exclusive right to acquire additional reserves, royalty interests and certain transportation infrastructure relating to future mine developments by The Cline Group. Simultaneous with the closing of this transaction, we signed a definitive agreement to purchase the reserves and transportation infrastructure at Cline’s Gatling Ohio complex. This transaction will close upon commencement of coal production, which is currently expected to occur in 2008. At the time of closing, NRP will issue Adena 2,280,000 additional Class B units, and the general partner of NRP will issue Adena an additional 9% interest in the general partner and the incentive distribution rights.

 

2006 Acquisitions

 

Quadrant.  On December 29, 2006, we acquired an estimated 70 million tons of aggregate reserves located in DuPont, Washington for $23.5 million in cash and assumed a utility local improvement obligation of approximately $3.0 million. Of these reserves, approximately 25 million tons are currently permitted. We will pay an additional $7.5 million when the remaining tons are permitted. If the permit is not obtained by December 2016, the unpermitted tons will revert back to Quadrant. We funded this acquisition with cash and borrowings under our credit facility.

 

Bluestone.  On December 18, 2006, we acquired approximately 20 million tons of low vol metallurgical coal reserves that are located above our Pinnacle reserves in Wyoming County, West Virginia for $20 million. We funded this acquisition with borrowings under our credit facility.

 

D.D. Shepherd.  On December 1, 2006, we acquired nearly 25,000 acres of land containing in excess of 80 million tons of coal reserves for $110 million. The property is located in Boone County, West Virginia adjacent to other NRP property and consists of both metallurgical and steam coal reserves, gas reserves, surface and timber. We funded this acquisition with borrowings under our credit facility.

 

Red Fox.  On September 1, 2006, we acquired the Red Fox preparation plant and coal handling facility located in McDowell County, West Virginia for approximately $8.1 million, of which $4.1 million was paid at closing and the remainder was paid during the third and fourth quarters as construction was completed. This acquisition was the second under our memorandum of understanding with Taggart Global, LLC (formerly Sedgman USA, LLC). The plant will handle an estimated 20 million tons of coal reserves during its life. The initial $4.1 million payment paid at closing was funded through cash and borrowings under our credit facility and the remaining payments were funded with cash.

 

Coal Mountain.  On August 24, 2006, we acquired the Coal Mountain preparation plant, handling facility and rail load-out facility located in Wyoming County, West Virginia for $16.1 million under our memorandum of understanding with Taggart Global. We expect that approximately 35 million tons of coal will be processed through this facility during its life. We paid for the facilities with cash and with borrowings under our credit facility as construction was completed in phases during the third and fourth quarters.

 

Williamson Development.  On January 20, 2006 and August 15, 2006, we closed the second and third phases of the Williamson Development acquisition in Illinois for $35 million each. We funded the January 20, 2006 acquisition with proceeds from the issuance of senior notes and the August 15, 2006 acquisition with borrowings under our credit facility.

 

Allegany County, Maryland.  On June 29, 2006, we acquired 3.3 million tons of coal in Allegany County, Maryland for $5.5 million in cash.

 

Indiana Reserves.  On May 26, 2006, we acquired 16.3 million tons of coal reserves and an overriding royalty interest on an additional 2.4 million tons for $10.85 million in cash. These reserves are located in Pike, Warrick and Gibson Counties in Indiana.

 

Coal Royalty Revenues, Reserves and Production

 

The following table sets forth coal royalty revenues and average coal royalty revenue per ton from the properties that we owned or controlled for the years ending December 31, 2006, 2005 and 2004. Coal royalty revenues were generated from the properties in each of the areas as follows:

 

 

The following table sets forth production data and reserve information for the properties that we owned or controlled for the years ending December 31, 2006, 2005 and 2004. All of the reserves reported below are recoverable reserves as determined by Industry Guide 7. In excess of 90% of the reserves listed below are currently leased to third parties. Coal production data and reserve information for the properties in each of the areas is as follows:

 

Production and Reserves

 

 

We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is coal which meets the standards of Phase II of the Clean Air Act and is that portion of low sulfur coal that, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu. As of December 31, 2006, approximately 36% of our reserves were compliance coal. Unless otherwise indicated, we present the quality of the coal throughout this Form 10-K on an as-received basis, which assumes 6% moisture for Appalachian reserves, 12% moisture for Illinois Basin reserves and 25% moisture for Northern Powder River Basin reserves. We own both steam and metallurgical coal reserves in Northern, Central and Southern Appalachia, and we own steam coal

reserves in the Illinois Basin and the Northern Powder River Basin. In 2006, approximately 28% of the production and 33% of the coal royalty revenues from our properties were from metallurgical coal.

 

The following table sets forth our estimate of the sulfur content, the typical quality of our coal reserves and the type of coal in each area as of December 31, 2006.

 

Sulfur Content, Typical Quality and Type of Coal

 

 

 

 

In 2005, we engaged several independent engineering firms to conduct reserve studies of our existing properties. However, as a result of the extensive nature of our reserve holdings and the large number of acquisitions that we consummate on an annual basis, this study will be an ongoing process. As of December 31, 2006, these studies had been completed with respect to approximately 44% of the tons we owned when we began the process, and a study is currently ongoing with respect to another 20% of the initial reserves. In connection with acquisitions, we have either commissioned new studies or relied on reports done prior to the acquisition. In addition to these studies, we base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

 

 

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.

 

Coal Transportation and Processing Revenues

 

In the second half of 2006, we acquired two preparation plants and coal handling facilities under our memorandum of understanding with Taggart Global. Together with a third coal preparation plant and rail load-out facility that we acquired in Greenbrier County, West Virginia in 2005, these facilities generated approximately $1.5 million in revenues in 2006. We do not operate the preparation plants, but receive a fee for coal processed through them.

 

Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed through the facilities.

 

In addition to our preparation plants, as part of the January 2007 Cline transaction, we acquired coal handling and transportation infrastructure associated with the Gatling mining complex in West Virginia and beltlines and rail load-out facilities associated with Williamson Energy’s Pond Creek No. 1 mine in Illinois. We also entered into an agreement to purchase the transportation infrastructure as well as the reserves at Cline’s Gatling Ohio complex. This complex is located in Meigs County, Ohio directly across the river from Cline’s West Virginia operation. In contrast to our typical royalty structure, we are operating the coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We anticipate that these assets will contribute significant revenues to NRP in future years.

 

Aggregates Royalty Revenues, Reserves and Production

 

In December 2006, we acquired an estimated 70 million tons of aggregate reserves located in DuPont, Washington for $23.5 million in cash and assumed a utility local improvement obligation of approximately $3.0 million. Of these reserves, approximately 25 million tons are currently permitted. We will pay an additional $7.5 million when the remaining tons are permitted, provided, however, that if they are not permitted by December 2016, the title to the remaining tons will revert back to Quadrant. The acquisition was effective as of December 1, 2006 and for the month of December we received $0.6 million in royalty revenues on 412,000 tons of production.

 

Oil, Gas and Timber Properties

 

For the year ended December 31, 2006, we derived approximately 5% of our total revenues from oil, gas and timber royalties in Kentucky, Virginia and Tennessee. The 2006 revenues include approximately $3.5 million related to the sale of substantially all of our then-existing timber properties. Subsequent to that sale we acquired approximately 24,000 acres of timber rights in the D.D. Shepard acquisition in December 2006 and another 31,000 acres of timber rights in the Dingess-Rum acquisition in January 2007. Nevertheless, we do not own the oil, gas or timber rights on the vast majority of our properties, and do not expect to receive material oil, gas or timber revenues in 2007.

 

Significant Customers

 

In 2006, Alpha Natural Resources, Inc. and its various subsidiaries, as lessees, collectively provided approximately 14% of our total revenues. Although the loss of Alpha as a lessee could have a material adverse effect on us, we do not believe that the loss of a single mine on any of our properties would have a material adverse effect on us. No other lessee contributed more than 10% of our total revenues in 2006.

 

Competition

 

We face competition from other land companies and from coal producers in purchasing coal reserves and royalty producing properties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation since 1976. The top ten producers have increased their share of total domestic coal production from 38% in 1976 to 64% in 2005. This consolidation has led to a number of our lessees’ parent companies having significantly larger financial and operating resources than their competitors. Our lessees compete with both large and small producers nationwide on the basis of coal price at the mine, coal

quality, transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity and steel, as well as environmental and government regulations, technological developments and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, oil and hydroelectric power.

 

Regulation and Environmental Matters

 

General.  Our lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing PCBs. Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated entirely. However, to our knowledge none of the violations to date, nor the monetary penalties assessed, have been material to our lessees. We do not currently expect that future compliance will have a material effect on us.

 

While it is not possible to quantify the costs of compliance by our lessees with all applicable federal, state and local laws and regulations, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because our lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. Although the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.

 

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for coal mined by our lessees. The possibility exists that new legislation or regulations may be adopted that have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and may require our lessees or their customers to change operations significantly or incur substantial costs that could impact us.

 

Air Emissions.  The Federal Clean Air Act and corresponding state and local laws and regulations affect all aspects of our business. The Clean Air Act directly impacts our lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under U.S. Environmental Protection Agency (or EPA) laws and regulations will make it more costly to operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could negatively impact our lessees’ ability to sell coal, which would have a material effect on our coal royalty revenues.

 

The EPA’s Acid Rain Program, provided in Title IV of the Clean Air Act, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the

EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulphurization systems, or “scrubbers,” or by reducing electricity generating levels.

 

The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants and other large stationary sources in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule (or CAIR), which will permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010, respectively. CAIR requires these states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state.

 

In March 2005, the EPA finalized the Clean Air Mercury Rule (or CAMR), which establishes a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. While currently the subject of extensive controversy and litigation, if fully implemented, CAMR would permit states to implement their own mercury control regulations or participate in an interstate cap-and-trade program for mercury emission allowances.

 

The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. For example, in December 2004, the EPA designated specific areas in the United States as in “non-attainment” with the new national ambient air quality standard for fine particulate matter. In November 2005, the EPA published proposed rules addressing how states would implement plans to bring applicable non-attainment regions into compliance with the new air quality standard. Under the EPA’s proposed rulemaking, states would have until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our lessees’ mining operations and their customers could be affected when the new standards are implemented by the applicable states.

 

In June 2005, the EPA announced final amendments to its regional haze program originally developed in 1999 to improve visibility in national parks and wilderness areas. As part of the new rules, affected states must develop implementation plans by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide and particulate matter.

 

The U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against a number of utilities with coal-fired electric generating facilities alleging violations of the new source review provisions of the Clean Air Act. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected, which could have an adverse effect on our coal royalty revenues.

 

Carbon Dioxide Emissions.  The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls for developed nations to reduce their emissions of greenhouse gases to five percent below 1990 levels by 2012. Carbon dioxide, which is a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005 for those nations that ratified the treaty.

 

In 2002, the United States withdrew its support for the Kyoto Protocol As the Kyoto Protocol becomes effective, there will likely be increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. The United States Congress has considered bills in the past that would regulate domestic carbon dioxide emissions, but such bills have not yet received sufficient Congressional support for passage into law. Several states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired electric generating facilities. For example, in December 2005, seven

northeastern states agreed to implement a regional cap-and-trade program to stabilize carbon dioxide emissions from regional power plants beginning in 2009.

 

It is possible that future federal and state initiatives to control carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, which could negatively impact our lessees’ coal sales, and thereby have an adverse effect on our coal royalty revenues.

 

Surface Mining Control and Reclamation Act of 1977.  The Surface Mining Control and Reclamation Act of 1977 (or SMCRA) and similar state statutes impose on mine operators the responsibility of reclaiming the land and compensating the landowner for types of damages occurring as a result of mining operations, and require mine operators to post performance bonds to ensure compliance with any reclamation obligations. Regulatory authorities may attempt to assign the liabilities of our coal lessees to us if any of these lessees are not financially capable of fulfilling those obligations. In conjunction with mining the property, our coal lessees are contractually obligated under the terms of our leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation of the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.

 

Hazardous Materials and Waste.  The Federal Comprehensive Environmental Response, Compensation and Liability Act (or CERCLA or the Superfund law), and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources.

 

Some products used by coal companies in operations generate waste containing hazardous substances. We could become liable under federal and state Superfund and waste management statues if our lessees are unable to pay environmental cleanup costs. CERCLA authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons the costs they incurred in connection with such response. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment.

 

Water Discharges.  Our lessees’ operations can result in discharges of pollutants into waters. The Clean Water Act and analogous state laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants such as from spill or leak incidents is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of fill material and certain other activities in wetlands unless authorized by an appropriately issued permit.

 

Our lessees’ mining operations are strictly regulated by the Clean Water Act, particularly with respect to the discharge of overburden and fill material into waters, including wetlands. Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. A July 2004 decision by the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the U.S. Army Corps of Engineers from issuing further permits pursuant to Nationwide Permit 21, which is a general permit issued by the U.S. Army Corps of Engineers to streamline the process for obtaining permits under Section 404 of the Clean Water Act. While the decision was vacated by the Fourth Circuit Court of Appeals in November 2005, a similar lawsuit filed in federal district court in Kentucky seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the U.S. Army Corps of Engineers. In the event that such lawsuits prove to be successful in adjoining jurisdictions, some of our lessees may be required to apply for individual discharge permits pursuant to Section 404

of the Clean Water Act in areas where they would have otherwise utilized Nationwide Permit 21. Such a change could result in delays in our lessees obtaining the required mining permits to conduct their operations, which could in turn have an adverse effect on our coal royalty revenues. Moreover, such individual permits are also subject to challenge.

 

The Clean Water Act also requires states to develop anti-degradation policies to ensure non-impaired waterbodies in the state do not fall below applicable water quality standards. These and other regulatory developments may restrict our lessees’ ability to develop new mines, or could require our lessees to modify existing operations, which could have an adverse effect on our coal royalty revenues.

 

The Federal Safe Drinking Water Act (or SDWA) and its state equivalents affect coal mining operations by imposing requirements on the underground injection of fine coal slurries, fly ash and flue gas scrubber sludge, and by requiring permits to conduct such underground injection activities. In addition to establishing the underground injection control program, the SDWA also imposes regulatory requirements on owners and operators of “public water systems.” This regulatory program could impact our lessees’ reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners.

 

Mine Health and Safety Laws.  The operations of our lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

 

Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. In January 2006, West Virginia passed a law imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. Similarly, on April 27, 2006, Kentucky Governor Ernie Fletcher signed mine safety legislation that includes requirements for increased inspections of underground mines and additional mine safety equipment and authorizes the assessment of penalties of up to $5,000 per incident for violations of mine ventilation or roof control requirements.

 

On June 15, 2006 the President signed new mining safety legislation that mandates similar improvements in mine safety practices; increases civil and criminal penalties for non-compliance; requires the creation of additional mine rescue teams, and expands the scope of federal oversight, inspection and enforcement activities. Earlier, the federal Mine Safety Health Administration announced the promulgation of new emergency rules on mine safety that took effect immediately upon their publication in the Federal Register on March 9, 2006. These rules address mine safety equipment, training, and emergency reporting requirements. Implementing and complying with these new laws and regulations could adversely affect our lessees’ coal production and could therefore have an adverse affect on our coal royalty revenues and our ability to make distributions.

 

Mining Permits and Approvals.  Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.

 

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for reclaiming the mined property, upon the completion of mining operations. Typically, our lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. In the past, our lessees have generally obtained their mining permits without significant delay. Our lessees have obtained or applied for permits to mine a majority of the reserves that are

currently planned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, there are no assurances that they will not experience difficulty in obtaining mining permits in the future.

 

Employees and Labor Relations

 

We do not have any employees. To carry out our operations, affiliates of our general partner employ approximately 55 employees who directly support our operations. None of these employees are subject to a collective bargaining agreement. Some of the employees of our lessees and sub-lessees are subject to collective bargaining agreements.

 

Segment Information

 

We conduct all of our operations in a single segment — the ownership and leasing of mineral properties and related transportation and processing infrastructure. All of our owned properties are subject to leases, and revenues are earned based on the volume of minerals extracted, processed or transported. We consider revenues from timber and oil and gas acquired as part of the acquisition of our mineral reserves to be incidental to our business focus and those revenues constitute less than 10% of our total revenues and assets. We anticipate that these assets will continue to be incidental to our primary business in the future.

 

Website Access To Company Reports

 

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

 

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.

 

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.

 

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.

 

Any change in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues.

 

According to the U.S. Department of Energy, domestic electric power generation accounts for approximately 90% of domestic coal consumption. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as natural gas, nuclear, fuel oil and hydroelectric power and environmental and other governmental regulations. We expect new power plants will be built to produce electricity. Some of these new power plants will be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the federal Clean Air Act may result in more electric power generators shifting from coal to natural-gas-fired power plants. In addition, in recent years there has been significant political discussion of the connection between the emission of greenhouse gases and global warming. The environmental lobby is applying substantial pressure on utilities to limit the construction of new coal-fired generation plants in favor of alternative sources of energy. To the extent that these efforts are successful, it could reduce the demand for our coal.

 

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

 

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

 

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

 

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.

 

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

 

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

 

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

 

If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease.

 

We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

 

 

 

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

 

Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues.

 

Our lessees produce a significant amount of the metallurgical coal that is used in both the U.S. and foreign steel industries. In 2006, approximately 28% of the coal production and 33% of the coal royalty revenues from our properties were from metallurgical coal. The steel industry has increasingly relied on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that our lessees mine could continue to decrease. Additionally, since the amount of steel that is produced is tied to global economic conditions, a decline in those conditions could result in the decline of steel, coke and coal production. Since metallurgical coal is priced higher than steam coal, some mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If these mines are unable to sell metallurgical coal, these mines may not be economically viable and may close.

 

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

 

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

 

Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves.

 

Our reserve estimates may vary substantially from the actual amounts of coal our lessees may be able to economically recover from our reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:

 

 

 

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

 

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

 

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

 

None.

 

Major Coal Properties

 

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

 

Northern Appalachia

 

AFG-Southwest PA.  The AFG property is located in Washington County, Pennsylvania. We acquired this property in November 2005. In 2006, 3.0 million tons were produced from this property. We lease this property to Conrhein Coal Company, a subsidiary of Consol Energy. Coal is produced from an underground mine and is transported by belt to a preparation plant operated by the lessee. Coal is shipped by both the CSX and Norfolk Southern railways to utility customers, such as American Electric Power and Allegheny Energy.

 

Kingwood.  The Kingwood property is located in Preston County, West Virginia. In 2006, 1.3 million tons were produced from this property. We lease this property to Kingwood Mining Company, LLC, a subsidiary of Alpha Natural Resources L.P. Coal is produced from an underground mine. It is transported by belt to a preparation plant operated by the lessee. Coal is shipped primarily by CSX railroad to utilities such as Allegheny Power, Mirant and VEPCO.

 

Sincell.  The Sincell property is located in Garrett County, Maryland. In 2006, 728,000 tons were produced from this property. We lease this property to Mettiki Coal, LLC, a subsidiary of Alliance Resource Partners L.P. Coal is produced from an underground mine and a surface mine. It is transported by belt or truck to a preparation plant operated by the lessee. Coal is shipped primarily by truck to the Mount Storm power plant of Dominion Power.

 

Gatling.  The Gatling property is located in Mason County, West Virginia. We acquired the property in January 2007 as part of the larger Cline transaction. Coal from this property will be mined from an underground mine and transported via belt line to a preparation plant on the property. Clean coal will be transported via beltline either directly to the customer or to a barge loading facility. Production on the property began in the fourth quarter of 2006.

 

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

 

 

Central Appalachia

 

D.D. Shepard.  The D.D. Shepard property is located in Boone County, West Virginia. This property is primarily leased to a subsidiary of Peabody Energy. We acquired the property effective December 1, 2006, and 486,000 tons were produced from this property in December. Both steam and metallurgical coal is produced by the lessees from underground and surface mines. Coal is transported from the mines via belt or truck to preparation plants on the property. Coal is shipped via the CSX railroad to customers such as Appalachian Power.

 

VICC/Alpha.  The VICC/Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2006, 6.7 million tons were produced from this property. We primarily lease this property to Alpha Land and Reserves, LLC. Production comes from both underground and surface mines and is trucked to one of four preparation plants. Coal is shipped via both the CSX and Norfolk Southern railroads to utility and metallurgical

customers. Major customers include American Electric Power, Southern Company, Tennessee Valley Authority, VEPCO and U.S. Steel.

 

Lynch.  The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2006, 5.3 million tons were produced from this property. We primarily lease the property to Resource Development, LLC, an independent coal producer. Production comes from both underground and surface mines. Coal is transported by truck to a preparation plant on the property and is shipped primarily on the CSX railroad to utility customers such as Georgia Power and Orlando Utilities.

 

Pinnacle Property.  The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. This property is leased to PinnOak Resources, LLC. In 2006, 2.2 million tons were produced from this property. Metallurgical coal is produced from two underground mines and transported by belt or truck to a preparation plant operated by the lessee. Coal is shipped via the Norfolk Southern railroad to customers such as U.S. Steel, National Steel, and is exported to a number of customers located in Europe.

 

Lone Mountain.  The Lone Mountain property is located in Harlan County, Kentucky. In 2006, 2.5 million tons were produced from this property. We lease the property to Ark Land Company, a subsidiary of Arch Coal, Inc. Production comes from underground mines and is transported primarily by beltline to a preparation plant on adjacent property and shipped on the Norfolk Southern or CSX railroads to utility customers such as Georgia Power and the Tennessee Valley Authority.

 

Pardee.  The Pardee property is located in Letcher County, Kentucky and Wise County Virginia. In 2006, 2.0 million tons were produced from this property. We lease the property to Ark Land Company, a subsidiary of Arch Coal, Inc. Production comes from underground and surface mines and is transported by truck or beltline to a preparation plant on the property and shipped primarily on the Norfolk Southern railroad to utility customers such as Georgia Power and the Tennessee Valley Authority and metallurgical customers such as Algoma Steel and Arcelor.

 

VICC/Kentucky Land.  The VICC/Kentucky Land property is located primarily in Perry, Leslie and Pike Counties, Kentucky. In 2006, 4.0 million tons were produced from this property. Coal is produced from a number of lessees from both underground and surface mines. Coal is shipped primarily by truck but also on the CSX and Norfolk Southern railroads to customers such as Southern Company, Tennessee Valley Authority, and American Electric Power.

 

Dingess-Rum.  The Dingess-Rum property is located in Logan, Clay and Nicholas Counties, West Virginia. This property is leased to subsidiaries of Massey Energy and Magnum Coal. We acquired this property effective January 1, 2007. Both steam and metallurgical coal are produced underground and surface mines and transported by belt or truck to preparation plants on the property. Coal is shipped via the CSX railroad to steam customers such as American Electric Power, Dayton Power and Light, Detroit Edison and to various export metallurgical customers.

 

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

 

Southern Appalachia

 

BLC Properties.  The BLC properties are located in Kentucky, Tennessee, and Alabama. In 2006, 3.4 million tons were produced from these properties. We lease this property to a number of operators including Appolo Fuels Inc., Bell County Coal Corporation and Kopper-Glo Fuels. Production comes from both underground and surface mines and is trucked to preparation plants and loading facilities operated by our lessees. Coal is transported by truck and is shipped via both CSX and Norfolk & Southern railroads to utility and industrial customers. Major customers include Southern Company, South Carolina Electric & Gas, and numerous medium and small industrial customers.

 

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

 

Illinois Basin

 

Hocking-Wolford/Cummings.  The Hocking-Wolford property and the Cummings property are both located in Sullivan County, Indiana. In 2006, 1.4 million tons were produced from the properties. Both properties are under common lease to Black Beauty Coal Company, an affiliate of Peabody Energy. Production is currently from a surface mine, and coal is shipped by truck and railroad to customers such as Public Service of Indiana and Indianapolis Power and Light.

 

Sato.  The Sato property is located in Jackson County, Illinois. In 2006, 1.1 million tons were produced from the property. The property is under lease to Knight Hawk Coal LLC an independent coal producer. Production is currently from a surface mine, and coal is shipped by truck and railroad to various Midwest and southeast utilities.

 

Williamson Development.  The Williamson Development property is located in Franklin and Williamson Counties, Illinois. In mid-2006, we completed the final phase of the acquisition of this property and production began at the mine in the fourth quarter of 2006. In 2006, 66,000 tons were produced from the mine in the initial startup phase. Production is from an underground mine which will eventually use a longwall to produce coal. Production is shipped primarily via CN railroad to customers such as Cinergy. Also, as part of the Cline acquisition we acquired acreage adjacent to the Williamson Development property that will be developed in conjunction with the same mine producing on the Williamson Development property.

 

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

 

 

Northern Powder River Basin

 

Western Energy.  The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2006, 6.5 million tons were produced from our property. Western Energy Company, a subsidiary Westmoreland Coal Company, has two coal leases on the property. Western Energy produces coal by surface dragline mining, and the coal is transported by either truck or beltline to the four-unit 2,200-megawatt Colstrip generation station located

at the mine mouth and by the Burlington Northern Santa Fe railroad to Minnesota Power. A small amount of coal is transported by truck to other customers.

 

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

 

 

Title to Property

 

Of the approximately 2.1 billion tons of proven and probable coal reserves that we owned or controlled as of December 31, 2006, we owned approximately 99% of the reserves in fee. We lease approximately 18.5 million tons, or 1% of our reserves, from unaffiliated third parties. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operations of our business.

 

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

 

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, we believe these claims will not have a material effect on our financial position, liquidity or operations.

 

None.

 

Our common units are listed and traded on the New York Stock Exchange (NYSE) under the symbol “NRP”. As of February 20, 2007, there were an estimated 23,900 beneficial owners of our common units. The computation of the approximate number of unitholders is based upon a broker survey.

 

The following table sets forth the high and low sales prices per common unit, as reported on the New York Stock Exchange Composite Transaction Tape from January 1, 2005 to December 31, 2006, and the quarterly cash distribution declared and paid with respect to each quarter per common unit.

 

 

In addition to common units, we have also issued subordinated units that are listed and traded on the NYSE under the symbol “NSP”. As of February 20, 2007, there were an estimated 3,400 beneficial owners of our subordinated units. The computation of the approximate number of unitholders is based upon a broker survey. The subordinated units were issued as part of our initial public offering in October 2002 and receive a quarterly distribution only after sufficient funds have been paid to the common units, as described below. The subordinated units were held privately until August 2005, when a large holder of subordinated units sold 4,200,000 of its subordinated units in a public offering. Subsequently, this unitholder sold the remainder of its subordinated units in several block trades in December 2005.

 

The following table sets forth the high and low sales prices per subordinated unit, as reported on the New York Stock Exchange Composite Transaction Tape from August 10, 2005, the first day of trading, to December 31, 2006, and the quarterly cash distribution declared and paid with respect to each quarter per subordinated unit. In addition to the data in the table, prior to going public, the subordinated units received the same distributions every quarter as the common units.

 

 

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. If the subordination period ends, the common units will no longer be entitled to arrearages, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units will be converted into common units.

 

On November 14, 2005, 25% of the subordinated units converted into common units. On November 14, 2006, another 331/3% of the subordinated units outstanding on that date or 25% of the original outstanding subordinated units converted into common units. Providing that the minimum quarterly distribution has been earned and paid to both the common and subordinated units for the preceding 12 quarters, the remaining NSP subordinated units will convert into NRP common units automatically on November 14, 2007. Following the conversion in November 2007, NSP units will no longer exist and all subordinated units will have been converted into NRP units.

 

In connection with the Adena Minerals transaction, we issued 541,956 Class B units to Adena in January 2007. The Class B units are a new class of limited partnership interests in NRP that will be converted to regular common units upon the approval of our unitholders (other than Adena and its affiliates). The Class B Units are subordinate to the regular common units, but senior to the subordinated units, with respect to cash distributions (and in liquidation) and will be entitled to 110% of the cash distributions per common unit if they have not been converted to common units six months following the closing of the transactions contemplated by the Second Contribution Agreement (relating to Cline’s Gatling, Ohio complex) with Adena or September 30, 2008, whichever occurs first. The Class B Units are not listed for trading on the New York Stock Exchange.

 

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

 

Percentage Allocations of Available Cash From Operating Surplus

 

 

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, 2006, 2005, 2004, 2003 and 2002, and for the years ended December 31, 2006, 2005, 2004 and 2003 and the period from commencement of operations (October 17, 2002) through December 31, 2002 from the audited financial statements of Natural Resource Partners L.P. We derived the selected historical financial data for the members of the WPP Group (see page 2) for the period from January 1 through October 16, 2002 from the audited financial statements of the WPP Group, and we derived the selected historical financial data for the Arch Coal Contributed Properties for the period from January 1 through October 16, 2002 from the audited financial statements of the Arch Coal Contributed Properties.

 

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

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, 2006, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves in eleven states. For the year ended December 31, 2006, approximately 57% of the coal produced from our properties came from underground mines and approximately 43% came from surface mines. As of December 31, 2006, approximately 60% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 36% of our reserves.

 

We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell coal from our reserves in exchange for royalty payments. As of December 31, 2006, our reserves were subject to 180 leases with 70 lessees. For the year ended December 31, 2006, our lessees produced 52.1 million tons of coal generating $147.8 million in coal royalty revenues from our properties and our total revenues were $170.7 million. Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated sales departments. A significant portion of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. However, over the long term, our coal royalty revenues are affected by changes in the market price of coal.

 

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

 

Coal royalty revenues from our Appalachian properties represented 89% of our total coal royalty revenues for the year ended December 31, 2006, and thus a significant portion of our total revenue is dependent upon Appalachian coal prices. Coal prices are based on supply and demand, specific coal characteristics, economics of alternative fuel, and overall domestic and international economic conditions. Coal prices for both metallurgical and steam coal increased during 2005 and 2006, and as our lessees’ older contracts have rolled over during the last two years, we have received substantially higher royalties from our leases. Our revenue per ton from that region increased to an average of $3.07 per ton for the year ended December 31, 2006 from an average of $2.87 per ton for the same period of 2005. However, because prices have generally stabilized over the last year and our lessees will have fewer contracts that will rollover into substantially higher prices, we expect that our coal royalty revenue per ton will not continue to increase at this pace over the next year. In addition, in spite of the higher prices, most of our lessees have not appreciably increased production due to a number of constraints, including an increase in the cost of mining coal, increased customer stockpiles, a shortage of labor, permitting issues and rail transportation problems. As a result, we believe that a larger percentage of our future revenue growth will come from acquisitions of new reserves.

 

For the year ended December 31, 2006, approximately 33% of our coal royalty revenues and 28% of the related production were from metallurgical coal, which was sold to steel companies in the eastern United States, South America, Europe and Asia. Prices of metallurgical coal have been substantially higher over the last two years, and we expect them to remain at historically high levels in 2007 as well. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and export markets.

 

In addition to coal royalty revenues, we generated approximately 14% of our revenues for each of the years ended December 31, 2006 and 2005 from rentals; royalties on oil and gas and coalbed methane leases; timber; overriding royalty arrangements; coal processing fees; and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

 

We have recently acquired aggregate reserves near DuPont, Washington and coal processing and transportation infrastructure in West Virginia and Illinois. Although neither acquisition contributed materially to our 2006 revenues, we anticipate that both businesses will contribute significant revenues in 2007, and we hope to grow both businesses into meaningful complements to our coal royalty business.

 

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

 

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

 

Reconciliation of GAAP “Net cash provided by operating activities”
to Non-GAAP “Distributable cash flow”

 

 

Acquisitions

 

Recent Acquisitions

 

We are a growth-oriented company and have closed a number of accretive acquisitions over the last several years. Our most recent acquisitions are briefly described below.

 

2007 Acquisitions

 

Dingess-Rum.  On January 16, 2007, we acquired 92 million tons of coal reserves and approximately 33,700 acres of surface and timber in Logan, Clay and Nicholas Counties in West Virginia from Dingess-Rum Properties, Inc. As consideration for the acquisition, we issued 2,400,000 common units to Dingess-Rum.

 

Cline.  On January 4, 2007, we acquired 49 million tons of reserves in Williamson County, Illinois and Mason County, West Virginia that are leased to affiliates of The Cline Group. In addition, we acquired transportation assets and related infrastructure at those mines. As consideration for the transaction we issued 3,913,080 common units and 541,956 Class B units representing limited partner interests in NRP. Through its affiliate Adena Minerals, LLC, The Cline Group received a 22% interest in our general partner and in the incentive distribution rights of NRP in return for providing NRP with the exclusive right to acquire additional reserves, royalty interests and certain transportation infrastructure relating to future mine developments by The Cline Group. Simultaneous with the

closing of this transaction, we signed a definitive agreement to purchase the coal reserves and transportation infrastructure at Cline’s Gatling Ohio complex. This transaction will close upon commencement of coal production, which is currently expected to occur in 2008. At the time of closing, NRP will issue Adena 2,280,000 additional Class B units, and the general partner of NRP will issue Adena an additional 9% interest in the general partner and the incentive distribution rights.

 

2006 Acquisitions

 

Quadrant.  On December 29, 2006, we acquired an estimated 70 million tons of high quality aggregate reserves located in DuPont, Washington for $23.5 million in cash and assumed a utility local improvement obligation of approximately $3.0 million. Of these reserves, approximately 25 million tons are currently permitted. We will pay an additional $7.5 million when the remaining tons are permitted. If the permit is not obtained by December 2016, the unpermitted tons will revert back to Quadrant. We funded this acquisition with cash and borrowings under our credit facility.

 

Bluestone.  On December 18, 2006, we acquired approximately 20 million tons of low vol metallurgical coal reserves that are located above our Pinnacle reserves in Wyoming County, West Virginia for $20 million. We funded this acquisition with borrowings under our credit facility.

 

D.D. Shepherd.  On December 1, 2006, we acquired nearly 25,000 acres of land containing in excess of 80 million tons of coal reserves for $110 million. The property is located in Boone County, West Virginia adjacent to other NRP property and consists of both metallurgical and steam coal reserves, gas reserves, surface and timber. We funded this acquisition with borrowings under our credit facility.

 

Red Fox.  On September 1, 2006, we acquired the Red Fox preparation plant and coal handling facility located in McDowell County, West Virginia for approximately $8.1 million, of which $4.1 million was paid at closing and the remainder was paid during the third and fourth quarters as construction was completed. This acquisition was the second under our memorandum of understanding with Taggart Global, LLC (formerly Sedgman USA, LLC). The plant will handle an estimated 20 million tons of coal reserves during its life. The initial $4.1 million payment paid at closing was funded through cash and borrowings under our credit facility and the remaining payments were funded with cash.

 

Coal Mountain.  On August 24, 2006, we acquired the Coal Mountain preparation plant, handling facility and rail load-out facility located in Wyoming County, West Virginia for $16.1 million under our memorandum of understanding with Taggart Global. We expect that approximately 35 million tons of coal will be processed through this facility during its life. We paid for the facilities with cash and with borrowings under our credit facility as construction was completed in phases during the third and fourth quarters.

 

Williamson Development.  On January 20, 2006 and August 15, 2006, we closed the second and third phases of the Williamson Development acquisition in Illinois for $35 million each. We funded the January 20, 2006 acquisition with proceeds from the issuance of senior notes and the August 15, 2006 acquisition with borrowings under our credit facility.

 

Allegany County, Maryland.  On June 29, 2006, we acquired 3.3 million tons of coal in Allegany County, Maryland for $5.5 million in cash.

 

Indiana Reserves.  On May 26, 2006, we acquired 16.3 million tons of coal reserves and an overriding royalty interest on an additional 2.4 million tons for $10.85 million in cash. These reserves are located in Pike, Warrick and Gibson Counties in Indiana.

 

Disposition

 

Virginia Timber Properties.  For the year ended December 31, 2006, we received total proceeds of $7.1 million and recorded a total gain of $3.5 million related to transactions involving the sale of timber and related surface acreage located on our property in Wise and Dickenson Counties, Virginia.

 

Critical Accounting Policies

 

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

 

Aggregate Royalties.  We recognize aggregate royalty revenues on the basis of tons of aggregate sold by our lessees and the corresponding revenue from those sales. Generally, the aggregate lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of aggregate they sell, subject to a minimum annual payment.

 

Coal Processing Fees.  We recognize coal processing fees on the basis of tons of coal processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees of the coal processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal that is processed and sold from the facilities. The lessees are also subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time if sufficient royalties are generated from coal processing in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. The coal processing leases are structured so that the lessees are responsible for operating and maintenance expenses associated with the facilities.

 

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

 

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

 

Impact of Adoption of FAS 123R

 

We adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payment,” effective January 1, 2006 using the modified prospective approach. Prior to 2006, awards under our Long Term Incentive Plan were accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R provides that grants must be accounted for using the fair value method, which requires us to estimate the fair value of the grant and charge the estimated fair value to expense over the service or vesting period of the grant. In addition, FAS 123R requires that we include estimated forfeitures in our periodic computation of the fair value of the liability and that the fair value be recalculated at each reporting date over the service or vesting period of the grant. FAS 123R required us to recognize the cumulative effect of the accounting change at the date of adoption based on the

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

Results of Operations