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

Executive Overview

Our Business

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, 2008, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves, 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 22% of our 2008 revenues from other sources, compared to 20% in 2007. 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; overriding royalties; wheelage payments and timber.

Current Market Conditions and our Liquidity

Our business model depends in large part on our ability to make acquisitions and finance those acquisitions through the issuance of long-term debt or equity in the capital markets. As of December 31, 2008, we had in excess of $250 million in available capacity under our existing credit facility, as well as approximately $90 million in cash. Following our Macoupin acquisition in January 2009, we had $169 million in available capacity under the facility, and have committed to fund another $60 million as certain performance milestones are met in connection with the development of the Shay No. 1 mine in Illinois. Our credit facility does not mature until March 2012. In addition, because we amortize substantially all of our long-term debt, we have no need to pay off or refinance any debt obligations in 2009, other than our regularly scheduled principal payments. However, given the number of potential acquisitions that we evaluate on a regular basis, we could use up this capacity in a short period of time. In the past, we have been able to pay down our credit line by issuing equity or long-term senior notes at attractive interest rates.

As a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and refused to refinance existing debt at maturity at all or on similar terms. Although the lenders under our credit facility have indicated to us that they intend to honor their commitments, we are aware of some cases in which lenders have refused to provide funding to borrowers in spite of existing commitments.

If funding is not available when needed, or is available only on unfavorable terms, we may be unable to complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues, results of operations and quarterly distributions.

Current Results and Outlook

As of December 31, 2008, our reserves were subject to 201 leases with 73 lessees. For the year ended December 31, 2008, our lessees produced 60.6 million tons of coal generating $226.3 million in coal royalty revenues from our properties, and our total revenues were $291.7 million.

Global and domestic prices for physical delivery of coal by our lessees remained high during most of 2008, resulting in a substantial increase in our royalty per ton in Appalachia and the Illinois Basin compared to the same period in 2007. In recent months, however, commodity prices, including coal prices, have declined in the financial markets, and we expect to see lower prices for coal that is not contracted in 2009. As of the end of 2008, our lessees had contracted to sell approximately 90% of their steam coal in 2009 and approximately 60% of their metallurgical coal. We also expect that some metallurgical coal customers will decline to take delivery of contracted tons in 2009, which could ultimately result in a decline in production from our properties.

Even though coal royalty revenues from our Appalachian properties represented 66% of our total revenues in 2008, this percentage has continued to decline and we are diligently working to diversify our holdings by expanding our presence in the Illinois Basin, where our coal royalty revenues nearly tripled over 2007. Through our relationship with the Cline Group, we expect our Illinois assets to contribute even more significantly to our total revenues in 2009.

In addition, in 2008 we benefited from our significant exposure to metallurgical coal. Approximately 30% of our coal royalty revenues and 22% of the related production during 2008 were from metallurgical coal, which is used in the production of steel. The U.S. coal market, especially for Appalachian metallurgical coal, is being impacted by the global economic slowdown and it is difficult to determine how this will impact coal production from our properties or the prices that our lessees receive for the sale of the coal.

In addition to the issues being created by the current economy, the political, legal and regulatory environment is becoming increasingly difficult for the coal industry. The recent 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 substantial regulatory uncertainty. If these cases have adverse outcomes, it could have long-term negative implications for the future of all coal mining in Appalachia, which would impact our coal royalty revenues derived from that region. The Fourth Circuit reversed both orders on February 13, 2009, but the order will not take effect until a "mandate" is issued by that Court. A mandate will not issue for at least 14 days and could be delayed by a request for reconsideration. Thereafter, the original plaintiffs have 90 days in which to ask the United States Supreme Court to review the decision. If the Fourth Circuit decision stands, then a backlog of permits pending before the Corps of Engineers may ease.

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 future 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"

                                                              For the Years Ended December 31,
                                                            2008             2007           2006

Net cash provided by operating activities                $   229,956       $ 168,153      $ 138,843
Less scheduled principal payments                            (17,234 )        (9,350 )       (9,350 )
Less reserves for future principal payments                  (17,235 )       (13,388 )       (9,600 )
Add reserves used for scheduled principal payments            17,234           9,400          9,400

Distributable cash flow                                  $   212,721       $ 154,815      $ 129,293

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.

Macoupin. On January 27, 2009, we acquired coal reserves and infrastructure assets related to the Shay No. 1 mine in Macoupin County, Illinois for $143.7 million from Macoupin Energy, LLC, an affiliate of the Cline Group. Upon closing, we paid $83.7 million and will make three subsequent payments of $20 million each in 2009 based upon performance measures associated with the development of a new mine.

Coal Properties. In October 2008, we acquired an overriding royalty for $5.5 million from Coal Properties Inc. This overriding royalty agreement is for coal reserves located in the states of Illinois and Kentucky.

Mid-Vol Coal Preparation Plant. In April 2008, we completed construction of a coal preparation plant and coal handling infrastructure under our memorandum of understanding with Taggart Global USA, LLC. The total cost to build the facilities was $12.7 million.

Licking River Preparation Plant. In March 2008, we signed an agreement for the construction of a coal preparation plant facility under our memorandum of understanding with Taggart Global USA, LLC. The cost for the facility, located in Eastern Kentucky, is estimated to be approximately $8.7 million, of which $8.4 million had been paid as of December 31, 2008 for construction costs incurred to date.

Massey Energy. In December 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. In December 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. In August 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.

Mettiki. In April 2007, we acquired approximately 35 million tons of coal reserves in Grant and Tucker Counties in Northern West Virginia in exchange for 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. In February 2007, we acquired an overriding royalty from Westmoreland Coal Company for $12.7 million on 225 million tons of coal that are being mined by a subsidiary of Peabody Energy in the Powder River Basin. The reserves are located in the Rocky Butte Reserve in Wyoming.

Dingess-Rum. In January 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 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 8,910,072 units representing limited partner interests in NRP.

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.

Minimum Royalties. Most of our 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.

Asset Impairment. If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.

Share-Based Payments. We account for awards under our Long-Term Incentive Plan under Financial Accounting Standards Board Statement No. 123R, Share Based Payment. 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 or credit the estimated fair value to expense over the service or vesting period of the grant based on fluctuations in value. In addition, FAS 123R requires that estimated forfeitures be included in the 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.

Recent Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value methods. This statement does not require any new fair value measurements. Instead, it provides for increased consistency and comparability in fair value measurements and for expanded disclosure surrounding the fair value measurements whenever other standards require (or permit) the measurement of assets or liabilities at fair value. This statement is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Accordingly, we adopted SFAS No. 157 on January 1, 2008. The adoption of this statement did not have a material impact our financial position, results of operations or cash flows. In February 2008, the FASB issued FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. The standard provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. We did not elect the fair value option for any financial assets or financial liabilities as of January 1, 2008, the effective date of the standard.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), "Business Combinations". The statement establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008. Accordingly, any business combinations we complete in 2009 or thereafter will be recorded and disclosed following the new standard. We expect SFAS No. 141R to have an impact our consolidated financial statements when we complete a business combination, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after the effective date.

In December 2007, the FASB issued SFAS No. 160, "Non-controlling Interests in Consolidated Financial Statements," which provides guidance for accounting and reporting of non-controlling (minority) interests in consolidated financial statements. The statement is effective for fiscal years and interim periods within fiscal years beginning on or after December 15, 2008. At the current time, we do not hold minority interests in subsidaries, therefore we expect that SFAS No. 160 will have no impact on our financial condition or results of operations.

In March 2008, the FASB issued EITF No. 07-4, which considers whether the incentive distribution rights, or IDRs, of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The EITF considers whether the partnership

agreement contains any contractual limitations concerning distributions to IDR holders that would impact the amount of earnings to allocate to the IDR holders for each reporting period. If distributions are contractually limited to the IDR holders' share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the IDR holders. In addition, the EITF presents alternative methods for inclusion of IDRs in the earnings per unit computation. When cash distributions exceed net income for the period, net income should be reduced by the distributions made to the holders of the general partner interest, the holders of the limited partner interests and IDR holders for the period. The provisions of EITF No. 07-4 are effective for fiscal years beginning after December 15, 2008. We are currently evaluating the requirements of EITF No. 07-4 to determine the impact, if any, on our consolidated financial statements.

In June 2008, the FASB issued Staff Position ("FSP") No. EITF No. 03-6-1 "Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities." This FSP affects entities that accrue cash dividends on share-based payment awards during the awards' service period when the dividends do not need to be returned if the employees forfeit the award. The FSP requires that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders and are considered participating securities. Because the awards are considered participating securities, the issuing entity is required to apply the two-class method of computing basic and diluted earnings per share. The provisions of FSP No. EITF No. 03-6-1 are effective for fiscal years beginning after December 15, 2008. We are currently evaluating the requirements of FSP No. EITF 03-6-1, to determine the impact and do not expect this to have any impact on our consolidated financial statements.

Results of Operations

               Summary of 2008 and 2007 Royalties and Production


                                                     For the Years Ended
                                                        December 31,                Increase         Percentage
                                                     2008            2007          (Decrease)          Change
                                                         (In thousands, except percent and per ton data)

Coal royalties
Appalachia
Northern                                         $     17,074      $  16,664      $        410                 2 %
Central                                               156,109        117,820            38,289                32 %
Southern                                               19,839         17,832             2,007                11 %

Total Appalachia                                      193,022        152,316            40,706                27 %
Illinois Basin                                         21,695          7,963            13,732               172 %
Northern Powder River Basin                            11,533         11,064               469                 4 %

Total                                            $    226,250      $ 171,343      $     54,907                32 %

Production (tons)
Appalachia
Northern                                                5,799          7,270            (1,471 )             (20 )%
Central                                                35,967         35,835               132                <1 %
Southern                                                4,273          4,603              (330 )              (7 )%

Total Appalachia                                       46,039         47,708            (1,669 )              (3 )%
Illinois Basin                                          8,313          3,709             4,604               124 %
Northern Powder River Basin                             6,218          5,815               403                 7 %

Total                                                  60,570         57,232             3,338                 6 %

Average gross royalty revenue per ton
Appalachia
Northern                                         $       2.94      $    2.29      $       0.65                28 %
Central                                                  4.34           3.29              1.05                32 %
Southern                                                 4.64           3.87               .77                20 %
Total Appalachia                                         4.19           3.19              1.00                31 %
Illinois Basin                                           2.61           2.15               .46                21 %
Northern Powder River Basin                              1.85           1.90              (.05 )              (3 )%
Combined average gross royalty revenue per ton           3.74           2.99               .75                25 %
Aggregates
Royalty revenues                                 $      6,275      $   6,778      $       (503 )              (7 )%
Aggregate Bonus Royalty                          $      2,844      $     656      $      2,188               334 %
Production                                              4,791          5,698              (907 )             (16 )%
Average gross royalty revenue per ton            $       1.31      $    1.19      $       0.12                10 %

. . .