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Article by DailyStocks_admin    (10-13-08 08:51 AM)

Natural Resource Partners L.P. CEO CORBIN J JR ROBERTSON bought 40000 shares on 10-01-2008 at $24.75

BUSINESS OVERVIEW

Business

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, 2007, 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, 2007, our coal reserves were subject to 191 leases with 66 lessees. In 2007, our lessees produced 57.2 million tons of coal from our properties and our coal royalty revenues were $171.3 million.

Beginning 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. During 2007, our lessees produced 5.7 million tons of aggregates and our aggregate royalties were $7.4 million. Coal processing fees and coal transportation fees added $4.8 million and $4.0 million, respectively.

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.

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 may 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. 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 long-term and spot coal prices, lessees’ supply contracts and the royalty rates in our leases. 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 as coal is produced.

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 retiree health care legacy costs, black lung benefits and workers’ compensation costs associated with operating the mines. We typically pay property taxes and then are reimbursed by the lessee for the taxes on their 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 acquisitions over the last several years. Our most recent acquisitions are briefly described below. We finance our acquisitions through a combination of cash on hand, our credit facility and equity.

2007 Acquisitions

Massey Energy. On December 31, 2007, we acquired an overriding royalty interest from Massey Energy for $6.6 million. The override relates to low-vol metallurgical coal reserves that are being produced from the Pinnacle Mine in West Virginia.

National Resources. On December 17, 2007, we acquired approximately 17.5 million tons of high quality low-vol metallurgical coal reserves in Wyoming and McDowell Counties in West Virginia from National Resources, Inc., a subsidiary of Bluestone Coal. Total consideration for this purchase was $27.2 million.

Cheyenne Resources. On August 16, 2007, we acquired a rail load-out facility and rail spur from Cheyenne Resources for $5.5 million. This facility is located in Perry County, Kentucky.

Mid-Vol Coal Preparation Plant. On May 21, 2007, we signed an agreement for the construction of a coal preparation plant, coal handling infrastructure and a rail load-out facility under our memorandum of understanding with Taggart Global USA, LLC. Consideration for the facility, located near Eckman, West Virginia, is estimated to be approximately $16.2 million, of which $11.2 million has been paid as of December 31, 2007 for construction costs incurred to date.

Mettiki. On April 2, 2007, we acquired approximately 35 million tons of coal reserves in Grant and Tucker Counties in Northern West Virginia for total consideration of 500,000 common units and approximately $10.2 million in cash. The assets were acquired from Western Pocahontas Properties Limited Partnership under our omnibus agreement. Western Pocahontas Properties has retained an overriding royalty interest on approximately 16 million tons of non-permitted reserves, which will be offered to us at the time those reserves are permitted.

Westmoreland. On February 27, 2007, we acquired an overriding royalty on 225 million tons of coal that are being mined by a subsidiary of Peabody Energy in the Powder River Basin from Westmoreland Coal Company for $12.7 million. The reserves are located in the Rocky Butte Reserve in Wyoming.

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 4,800,000 common units to Dingess-Rum.

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 7,826,160 common units and 1,083,912 Class B units representing limited partner interests in NRP. The Class B units were converted to common units during the second quarter of 2007.

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 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.

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.

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.

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 of 2006 as construction was completed. This acquisition was the second under our memorandum of understanding with Taggart Global. The plant will handle an estimated 20 million tons of coal reserves during its life.

Coal Mountain. On August 24, 2006, we acquired the Coal Mountain preparation plant, coal handling 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.

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. Upon the completion of the third phase, we had acquired a total of 87.5 million tons of coal reserves for an aggregate purchase price of $105 million.

Allegany County, Maryland. On June 29, 2006, we acquired 3.3 million tons of coal in Allegany County, Maryland for $5.5 million. 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. 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, 2007, 2006 and 2005.

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, 2007, approximately 38% 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 2007, approximately 23% of the production and 29% 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, 2007.

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 complete on an annual basis, these studies will be an ongoing process. As of December 31, 2007, studies had been completed with respect to approximately 59% of the tons we owned when we began the process, and we anticipate completing studies on an additional 10% to 20% of those reserves by the end of 2008. In connection with acquisitions, we have either commissioned new studies or relied on recent 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. Some of these factors and assumptions include:


• future coal prices, mining economics, capital expenditures, severance and excise taxes, and development and reclamation costs;

• future mining technology improvements;

• the effects of regulation by governmental agencies; and

• geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in other areas of our reserves.

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 royalties that vary from our expectations.

Coal Transportation and Processing Revenues

We have acquired four preparation plants and related coal handling facilities, in addition to other coal processing infrastructure such as rail spurs and rail load-out facilities. We do not operate these facilities, 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. These facilities generated $4.8 million in coal processing revenues for 2007.

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. For the year ended December 31, 2007, we reported $4.0 million in revenue from these assets.

Aggregates Royalty Revenues, Reserves and Production

We own an estimated 65 million tons of aggregate reserves located in DuPont, Washington. Of these reserves, approximately 20 million tons are currently permitted. If the remaining tons are not permitted by December 2016, the title to those tons will revert back to the seller of the reserves. During 2007, we received $7.4 million in royalty revenues on 5.7 million tons of production.

Oil and Gas Properties

For the years ended December 31, 2007 and 2006, we derived approximately 2.3% and 2.5%, respectively, of our total revenues from oil and gas royalties in Kentucky, Virginia and Tennessee.

Significant Customers

In 2007, we did not have any single lessee that contributed more than 10% of our total revenues, and we do not believe that the loss of any one lessee would have a material adverse effect on our partnership.

Competition

We face competition from other land companies, coal producers, as well as private equity firms in purchasing coal reserves and royalty producing properties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation since 1976. The top ten producers have increased their share of total domestic coal production from 38% in 1976 to 65% in 2006. 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 government regulations, technological developments and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas 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 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 closures, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because our lessees are both contractually liable and liable under the permits they hold for all costs relating to their mining operations, including the costs of reclamation and mine closures. 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. In recent years, compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.

In addition, the electric 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 could 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 and regional implementation plans, could make coal a less attractive fuel source 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, promulgated in Title IV of the Clean Air Act Amendments of 1990, 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. Because the Acid Rain program is a mature program, we believe that all economic impacts of the program have now been factored into the demand and market for coal nationally.

In 1997, the EPA promulgated a rule, referred to as the “NOx SIP Call,” that required 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. We believe that the financial impact of the CAIR on coal markets has been factored into the price of coal nationally and that its impact on demand has largely been taken into account by the market place.

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 a new, more stringent national air quality standard for fine particulate matter and has proposed a more stringent standard for ozone. 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 “non-attainment” areas, meaning that the designated areas failed to meet the new national ambient air quality standard for fine particulate matter. In May of 2007, EPA published a final rule requiring that each State having a nonattainment area submit to EPA by April, 5 2008, an attainment demonstration and adopt regulations ensuring that the area will attain the standards as expeditiously as practicable, but no later than 2015. 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. Under the Regional Haze Rule, affected states were to have developed implementation plans by December 17, 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their plans by December 17, 2007, and EPA has yet to react to the situation. 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. In the mid - 1990’s, the Kyoto Protocol to the United Nations Framework Convention on Climate Change called 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. The United States has not ratified the Kyoto Protocol.

MANAGEMENT DISCUSSION FROM LATEST 10K

Executive Overview

Our Business

We engage principally in the business of owning, managing and leasing 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, 2007, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves in eleven states, and 59% of our reserves were low sulfur coal. 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.

Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Most of our coal is produced by large companies, many of which are publicly traded, with experienced and professional 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.

In our coal royalty business, our lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed royalty 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.

In addition to coal royalty revenues, we generated approximately 20% of our 2007 total revenues from other sources, compared to 13% for the same period in 2006. The increase represents our commitment to continuing to diversify our sources of revenue. These other sources include: aggregate royalties; coal processing and transportation fees; rentals; royalties on oil and gas and coalbed methane leases; timber stumpages; overriding royalty arrangements; and wheelage payments.

Current Results

As of December 31, 2007, our reserves were subject to 191 leases with 66 lessees. For the year ended December 31, 2007, our lessees produced 57.2 million tons of coal generating $171.3 million in coal royalty revenues from our properties, and our total revenues were $215 million.

Although we have recently acquired a large number of reserves in the Illinois Basin and diversified into aggregates and coal transportation and processing infrastructure, a significant portion of our total revenue remains dependent upon Appalachian coal production and prices. Coal royalty revenues from our Appalachian properties represented 71% of our total revenues for the year ended December 31, 2007. Approximately 29% of our coal royalty revenues and 23% of the related production during the year were from metallurgical coal, which is used in the production of steel.

Prices of metallurgical coal have been substantially higher than steam coal over the past few years, and we expect them to remain at high levels for the next several years. The current pricing environment for U.S. metallurgical coal is robust in both the domestic and export markets. Coal prices for both steam and metallurgical coal in Appalachia began to move in a positive direction during the second half of 2007, and the price movement accelerated at the end of 2007 and into 2008. The U.S. coal market, especially for coal from Appalachia and to a more limited extent the Illinois Basin, is being dramatically impacted by events in China, Australia and South Africa that are impacting world coal supply. Many observers believe that the growing world demand for coal may lead to an increasingly favorable pricing structure for all U.S. coal.

The Cline operations that we acquired in Illinois and West Virginia began to show modest improvement in the second half of 2007 over their performance in the first half of the year. We expect this trend to continue in 2008 as the operations continue to ramp up to their full production potential. Because the improved production from the mines will also directly impact the coal transportation revenues we receive from those properties, we continue to believe that these properties will be significant positive contributors to our revenue over the long-term.

Although coal prices have improved significantly, the political, legal and regulatory environment is becoming increasingly difficult for the coal industry. The 2007 judicial decisions by the Southern District of West Virginia regarding permits issued under Section 404 of the Clean Water Act in West Virginia, together with a similar lawsuit filed in Kentucky, have created significant regulatory uncertainty for the coal industry. If these cases have adverse outcomes, it could have long-term negative implications for the future of mining in Appalachia as well as our coal royalty revenues derived from that region.

Distributable Cash Flow

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.

Acquisitions

Recent Acquisitions

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

2007 Acquisitions

Massey Energy. On December 31, 2007, we acquired an overriding royalty interest from Massey Energy for $6.6 million. The override relates to low-vol metallurgical coal reserves that are being produced from the Pinnacle Mine in West Virginia.

National Resources. On December 17, 2007, we acquired approximately 17.5 million tons of high quality low-vol metallurgical coal reserves in Wyoming and McDowell Counties in West Virginia from National Resources, Inc., a subsidiary of Bluestone Coal. Total consideration for this purchase was $27.2 million.

Cheyenne Resources. On August 16, 2007, we acquired a rail load-out facility and rail spur from Cheyenne Resources for $5.5 million. This facility is located in Perry County, Kentucky.

Mid-Vol Coal Preparation Plant. On May 21, 2007, we signed an agreement for the construction of a coal preparation plant, coal handling infrastructure and a rail load-out facility under our memorandum of understanding with Taggart Global USA, LLC. Consideration for the facility, located near Eckman, West Virginia, is estimated to be approximately $16.2 million, of which $11.2 million had been paid as of December 31, 2007 for construction costs incurred to date.

Mettiki. On April 2, 2007, we acquired approximately 35 million tons of coal reserves in Grant and Tucker Counties in Northern West Virginia for total consideration of 500,000 NRP common units and approximately $10.2 million in cash. The assets were acquired from Western Pocahontas Properties under our omnibus agreement. Western Pocahontas Properties has retained an overriding royalty interest on approximately 16 million tons of non-permitted reserves, which will be offered to NRP at the time those reserves are permitted.

Westmoreland. On February 27, 2007, we acquired an overriding royalty on 225 million tons of coal in the Powder River Basin from Westmoreland Coal Company for $12.7 million. The reserves are located in the Rocky Butte Reserve in Wyoming.

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 4,800,000 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 7,826,160 common units and 1,083,912 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 late 2008 or early 2009. At the time of closing, NRP will issue Adena 4,560,000 additional 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.

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.

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.

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 of 2006 as construction was completed. This acquisition was the second under our memorandum of understanding with Taggart Global. The plant will handle an estimated 20 million tons of coal reserves during its life.

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.

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. Upon the completion of the third phase, we had acquired a total of 87.5 million tons of coal reserves for an aggregate purchase price of $105 million.

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

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. These reserves are located in Pike, Warrick and Gibson Counties in Indiana.

Dispositions

Virginia Land Sale. For the year ended December 31, 2007, we received proceeds of $1.4 million and recorded a gain of $1.2 million related to the sale of surface acreage located on our property in Wise County, Virginia.

Virginia Timber Properties. For the year ended December 31, 2006, we received proceeds of $7.1 million and recorded a 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 and Aggregate Royalties. Coal and aggregate royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell, subject to minimum annual or quarterly payments.

Coal Processing and Transportation Fees. Coal processing fees are recognized on the basis of tons of coal processed through the facilities by the Partnership’s 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 coal processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Coal transportation fees are recognized on the basis of tons of coal transported over the beltlines. Under the terms of the transportation contracts, we receive a fixed price per ton for all coal transported on the beltlines.

Oil and Gas Royalties. Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue when received and recognized as revenue 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.

Minimum Royalties. Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

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 proven 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.

Results of Operations

Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 80% and 87% of our total revenue for the years ended December 31, 2007 and 2006, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

Appalachia. As a result of acquisitions completed since the end of 2006 and higher prices, both coal royalty revenues and production in Appalachia increased in 2007. The Appalachian results by region are set forth below.

Northern Appalachia. Coal royalty revenues and production increased primarily due to acquisitions completed during 2007. Coal royalty revenues attributable to those acquisitions were $7.3 million and production was 2.7 million tons. These increases were partially offset by lower production and coal royalty revenues from our Sincell property where longwall mining was completed. The longwall on the Sincell property moved to the Beaver Creek property to reserves we acquired in the Mettiki acquisition.

Central Appalachia. Coal royalty revenues attributable to acquisitions completed in 2007 were $33.5 million and production was 9.2 million tons. Offsetting these increases was lower production on our VICC/Kentucky Land, Pinnacle, Dorothy and Evans Lavier properties, all of which had some mining activity move to adjacent properties, resulting in an aggregate $15.4 million reduction in coal royalty revenues from those properties for the current year compared to 2006.

Southern Appalachia. Our coal royalty revenues and production in Southern Appalachia decreased for the year ended December 31, 2007 compared to the year ended December 31, 2006 because our major lessees on our BLC Properties and Twin Pines/Drummond properties had more production coming from adjacent property.

Illinois Basin. Coal royalty revenues and production attributable to our Williamson and James River acquisitions was $2.9 million and production was 1.2 million tons for the current year. This increase was partially offset by reduced production and coal royalty revenues on our Trico property.

Northern Powder River Basin. The decrease in production on our Western Energy property was due to the normal variations that occur due to the checkerboard nature of our ownership, but was partially offset by higher prices being received by our lessee.

Aggregates Royalty Revenues, Reserves and Production. In December 2006, we acquired aggregate reserves located in DuPont, Washington. For the year ended December 31, 2007, we recorded $7.4 million in royalty revenues from aggregates and had production of 5.7 million tons. Nearly all of this production and revenue is attributable to the aggregate reserves in DuPont, Washington.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Coal Royalty Revenues and Production . Coal royalty revenues comprised approximately 79% and 80% of our total revenue for the three month periods ended June 30, 2008 and 2007. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Primarily due to higher prices being realized by our lessees, coal royalty revenues increased in the three month period ended June 30, 2008 compared to the same period of 2007, while production was only slightly higher. The Appalachian results by region are set forth below.
Northern Appalachia. Coal royalty revenues increased primarily due to higher prices across all areas.
Central Appalachia. Coal royalty revenues attributable to acquisitions completed since the end of the first half of 2007 were $1.6 million and production related to those acquisitions was 149,000 tons. Coal production on our other properties increased slightly but nearly all our lessees received higher prices resulting in higher per ton coal royalty revenue.

Southern Appalachia. Our coal royalty revenues and production in Southern Appalachia decreased for the quarter ended June 30, 2008 compared to the same period in 2007 due to decreased shipments from our Oak Grove property and the lessee on our Twin Pines/Drummond property moving to adjacent property. These decreases were slightly offset due to the higher prices received by nearly all our lessees.
Illinois Basin . Coal royalty revenues and production increased primarily due to the improved production on our Williamson property and a lessee moving back onto our property on the Cummings/Hocking Wolford property.
Northern Powder River Basin . Coal royalty revenues and production increased on our Western Energy property primarily due to the normal variations that occur due to the checkerboard nature of ownership. The higher per ton rate in the second quarter of 2007 was due to a cumulative price adjustment, which is received from time to time by our lessee.
Aggregates Royalty Revenues, Reserves and Production . Aggregate production decreased slightly, but due to improved prices being received by the lessee, royalty revenue increased slightly.

Coal Royalty Revenues and Production . Coal royalty revenues comprised approximately 78% and 81% of our total revenue for the six month periods ended June 30, 2008 and 2007. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Primarily due to higher prices being realized by our lessees and in part because of acquisitions completed since the first quarter of 2007, coal royalty revenues increased in the six month period ended June 30, 2008 compared to the same period of 2007, while production increased only slightly. The Appalachian results by region are set forth below.
Northern Appalachia. Coal royalty revenues increased primarily due to the lessee from the Mettiki acquisition made in the second quarter of 2007 operating on our property for the entire six month period in 2008 versus three months in 2007. This increase was partially offset by lower production on our AFC properties, where a greater proportion of the production for the six month period ended June 30, 2008 was on adjacent property.

Central Appalachia. Coal royalty revenues attributable to acquisitions completed since the end of the first half of 2007 were $2.7 million and production related to those acquisitions was 290,000 tons. Coal production on our other properties increased slightly, but the higher prices received by our lessees resulted in substantially higher coal royalty revenue per ton.
Southern Appalachia. Our coal royalty revenues in Southern Appalachia increased for the six months ended June 30, 2008 compared to the same period in 2007, but production decreased slightly. The production decreases occurred on our Oak Grove property, which had lower shipments, and our Twin Pines/Drummond property, where the lessee moved to adjacent property. The production decreases were more than offset by the higher prices received by our lessees.
Illinois Basin . Coal royalty revenues and production increased primarily due to the improved production on our Williamson property and a lessee moving back onto our Cummings/Hocking Wolford property.
Northern Powder River Basin . Coal royalty revenues and production increased on our Western Energy property primarily due to the normal variations that occur due to the checkerboard nature of ownership. The per ton revenue is lower for the six months ended June 30, 2008 compared to the same period in 2007. The higher per ton rate in the first six months of 2007 was due to a cumulative price adjustment, which is received from time to time by our lessee.
Aggregates Royalty Revenues, Reserves and Production . Aggregate production and royalties were down slightly for the six months ended June 30, 2008 compared to the same period of 2007. In the first half of 2008, we received a bonus royalty payment that was $1.6 million higher than expected from our lessee based on their 2007 net profits. The lower production was partially offset by higher prices being received by our lessee.
Other Operating Results
Coal Processing and Transportation Revenues . We generated $1.8 million and $3.7 million in processing revenues for the quarter and six months ended June 30, 2008 compared with $1.1 million and $2.0 million for the same periods in 2007. 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. Coal processed through the facility decreased 22% and 1% for the three and six month periods of 2008, compared to the same periods of 2007, while revenue increased due to the increase in sales prices.
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. In contrast to our typical royalty structure, we receive a fixed rate per ton for coal transported over these facilities. We operate coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We generated transportation fees from these assets of approximately $3.4 million and $5.0 million for the quarter and six months ended June 30, 2008, compared to $0.8 million and $1.3 million for the same periods of 2007. Production increased 497% for the second quarter and 380% for the first half of 2008 compared to the same periods in 2007, as we reported a full six months of transportation revenue in 2008 and production ramped up on our Williamson property.
Oil and Gas Royalties . We generated $1.9 million and $1.3 million for the quarter ended June 30, 2008 and 2007, respectively and for the six months ended June 30, 2008, we generated $3.4 million compared to $2.5 million for the same period in 2007. These increases in revenue are primarily due to higher prices.
Override revenues. Override revenues were $2.0 million and $1.0 million for the quarters ending June 30, 2008 and 2007, respectively and $4.5 million and $2.0 million for the six months ended June 30, 2008 and 2007, respectively. These increases were due primarily to override royalty acquisitions during 2007 and additional production on an existing override.
Other revenues. Other revenues, primarily comprised of rent and wheelage , generated $1.3 million for the quarter and $2.7 million for the six months ended June 30, 2008, compared to $1.2 million for the quarter and $2.3 million for the six months ended June 30, 2007.
Operating costs and expenses. Included in total expenses are:
• Depreciation, depletion and amortization of $16.7 million and $12.5 million for the quarters ended June 30, 2008 and 2007 and $31.8 million and $24.3 million for the six months ended June 30, 2008 and 2007, respectively. Depletion increased as a result of higher total production for 2008 and a greater portion of the production on the new properties that we acquired in 2007 and at the end of 2006, which are being depleted at much higher rates than our older properties.
• General and administrative expenses of $6.9 million and $11.0 million for the quarter and six month periods ended June 30, 2008 compared to $5.6 million and $12.2 million for the same periods during 2007. The change in general and administrative expense is primarily due to accruals under our long-term incentive plan attributable to fluctuations in our unit price.

• Property, franchise and other taxes have increased approximately $0.6 million for the quarter and $1.1 million year to date. The significant increase in 2008 was primarily due to increases in West Virginia taxes on additional properties we have acquired. A substantial portion of our property taxes is reimbursed to us by our lessees and is reflected as property tax revenue on our statement of income.
Interest Expense. Interest expense was virtually flat quarter to quarter and year to year. We replaced $225 million of our credit facility with senior notes at the end of March 2007 at a more favorable interest rate than those on our credit facility at that time which helped offset the increase in total debt outstanding.

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