price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for small or isolated mineral reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of minerals mined from our properties.
Transportation costs represent a significant portion of the total delivered cost for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make minerals 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 producers in other parts of the country.
Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals 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 minerals to their customers. Our lessees’ transportation providers may face difficulties in the future that may impair the ability of our lessees to supply minerals to their customers, resulting in decreased royalty revenues to us.
Lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.
Mineral supply contracts generally do not generally require operators to satisfy their obligations to their customers with resources mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with minerals 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 specifications. If a lessee satisfies its obligations to its customers with minerals from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues.
Our growing coal infrastructure business exposes us to risks that we do not experience in the royalty business.
Over the past three years, we have acquired several coal preparation plants, load-out facilities and beltlines. These facilities are subject to mechanical and operational breakdowns that could halt or delay the transportation and processing of coal, and therefore decrease our revenues. In addition, we have assumed the capital and operating risks associated with the transportation infrastructure at two mines. Although we havesub-contracted out this work to a third party, we could experience increased costs as well as increased liability exposure associated with operating these facilities.
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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 minerals 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 reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:
| • | future prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs; | |
| • | future mining technology improvements; | |
| • | the effects of regulation by governmental agencies; and | |
| • | geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in areas where our lessees currently mine. |
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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 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 royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.
Risks Inherent in an Investment in Natural Resource Partners L.P.
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.
Because distributions on the common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.
Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner.
Unitholders may not be able to remove our general partner even if they wish to do so.
Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general
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partner may not be removed except upon the vote of the holders of at least 662/3% of our outstanding units (including units held by our general partner and its affiliates). Because the owners of our general partner, along with directors and executive officers and their affiliates, own a significant percentage of our outstanding common units, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates.
In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwise change our management:
| • | generally, if a person acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and | |
| • | limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of management. |
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As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
We may issue additional common units without unitholder approval, which would dilute a unitholder’s existing ownership interests.
Our general partner may cause us to issue an unlimited number of common units, without unitholder approval (subject to applicable NYSE rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units without unitholder approval (subject to applicable NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
| • | an existing unitholder’s proportionate ownership interest in NRP will decrease; | |
| • | the amount of cash available for distribution on each unit may decrease; | |
| • | the relative voting strength of each previously outstanding unit may be diminished; and | |
| • | the market price of the common units may decline. |
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. In addition,Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Conflicts of interest could arise among our general partner and us or the unitholders.
These conflicts may include the following:
| • | we do not have any employees and we rely solely on employees of affiliates of the general partner; |
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| • | under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership; | |
| • | the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly distributions to unitholders; | |
| • | the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability; |
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| • | under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arms length negotiations; and | |
| • | the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights to one of its affiliates or to us. |
The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers with its own choices and to control their decisions and actions.
In addition, a change of control would constitute an event of default under our revolving credit agreement. During the continuance of an event of default under our revolving credit agreement, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to usand/or declare all amounts payable by us immediately due and payable. A change of control also may trigger payment obligations under various compensation arrangements with our officers.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
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laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us by any state will reduce the cash available for distribution to you.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
You will beare required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
Because our unitholders will beare treated as partners to whom we will allocate taxable income whichthat could be different in amount than the cash we distribute, you will beare required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities andnon-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), andnon-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions tonon-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, andnon-U.S. persons will be required to file United StatesU.S. federal income tax returns and pay tax on their share of our
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taxable income. If you are a tax exempt entity or anon-U.S. person, you should consult your tax advisor before investing in our common units.
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We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the Department of theU.S. Treasury and the IRSDepartment issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly traded partnerships are entitleditems. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to rely on these proposedchallenge our proration method or new Treasury Regulations they are not binding on the IRS and are subjectwere issued, we may be required to change until final Treasury Regulations are issued.the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
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The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in our filing two tax returns for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a
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publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a singleSchedule K-1 to unitholders for the tax years in which the termination occurs.
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.
As a result of investing in our common units, you may becomeare subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
In addition to federal income taxes, you willare likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You willare likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own property and conduct business in a number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns.
| Item 1B. | Unresolved Staff Comments |
None.
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| Item 2. | Properties |
Major Coal Properties
The following is a summary of our major coal producing properties in each region. For information regarding our Coal Reserves and Production as well as other information related to our coal properties, please see “Item 1. Business.”
Northern Appalachia
Beaver Creek. The Beaver Creek property is located in Grant and Tucker Counties, West Virginia. In 2009, 2.22010, 2.5 million tons were produced from this property. We lease this property to Mettiki Coal, LLC, a subsidiary of Alliance Resource Partners L.P. Coal is produced from an underground longwall mine. It is transported by truck to a preparation plant operated by the lessee. Coal is shipped primarily by truck to the Mount Storm power plant of Dominion Power.Power and to various export customers.
Gatling WV. The Gatling property is located in Mason County, West Virginia. In 2009, 406,000 tons were produced from the property. Coal from this property is mined from an underground mine and transported via belt line to a preparation plant on the property. Clean coal is transported via beltline either directly to American Electric Power or to a barge loading facility.
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is mined from an underground mine and transported via belt line to a preparation plant on the property. Clean coal is transported via beltline to a barge loading facility, from which it is transported via barge mainly to Allegheny Energy and American Electric Power.
Allegany County, Maryland. In 2010, 419,000 tons were produced from the property. We lease this property to Vindex Energy, a subsidiary of ICG. Coal from this property is produced from a surface mine. The raw coal is trucked to the Warrior plant of Allegheny Energy.
The map on the following pagebelow shows the location of our properties in Northern Appalachia.
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Central Appalachia
VICC/Alpha. The VICC/Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2009, 4.92010, 4.7 million tons were produced from this property. We primarily lease this property to Alpha Land and Reserves, LLC, a subsidiary of Alpha Natural Resources, Inc.Resources. 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 and to various export metallurgical customers.
Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2009, 4.12010, 4.6 million tons were produced from this property. We primarily lease the property to Resource Development, LLC, an independent coal producer.a subsidiary of Massey Energy. Production comes from both underground and surface mines. Coal is transported
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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.
VICC/Kentucky Land.The VICC/Kentucky Land property is located primarily in Perry, Leslie and Pike Counties, Kentucky. In 2009, 2.62010, 2.8 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.
Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. In 2009, 1.82010, 2.1 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.
D.D. Shepard. The D.D. Shepard property is located in Boone County, West Virginia. This property is primarily leased to a subsidiary of Patriot Coal Corp. In 2010, 1.8 million tons were produced from the property. Both steam and metallurgical coal are 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 various domestic and export metallurgical customers.
Pardee. The Pardee property is located in Letcher County, Kentucky and Wise County Virginia. In 2009, 1.42010, 1.3 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 domestic and export metallurgical customers such as Algoma Steel and Arcelor.
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 Patriot Coal. In 2010, 1.2 million tons were produced from the property. Both steam and metallurgical coal are produced from underground and surface mines and has been historically 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. During 2010, however, due to a fire at the Bandmill preparation plant, the coal that was produced from the property for most of the year was trucked to a remote preparation plant and then shipped via rail to customers. The preparation plant was rebuilt, renamed the Zigmond plant, and resumed operation in late 2010.
The map on the following page shows the location of our properties in Central Appalachia.
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Southern Appalachia
BLC Properties. The BLC properties are located in Kentucky Tennessee, and Alabama.Tennessee. In 2009, 2.42010, 1.7 million tons were produced from these properties. We lease these properties 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.
Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2009, 858,0002010, 1.1 million tons were produced from this property. We lease the property to Oak Grove Resources, LLC, a subsidiary of Cliffs Natural Resources, Inc. Production comes from an underground mine and is transported primarily by beltline to a preparation plant. The metallurgical coal is then shipped via railroad and barge to both domestic and export customers.
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The map below shows the location of our properties in Southern Appalachia.
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Illinois Basin
Macoupin. The Macoupin property is located in Macoupin County, Illinois. The property is under lease to an affiliate of the Cline Group, and in 2010, 791,000 tons were shipped from the property. Production is from an underground mine and is shipped via the Norfolk Southern or Union Pacific railroads or by barge to customers such as Western KY Energy and other midwest utilities or loaded into barges for shipment to export customers.
Sato. The Sato property is located in Jackson County, Illinois. In 2009, 567,0002010, 627,000 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.
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The map below shows the location of our properties in Illinois Basin.
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Northern Powder River Basin
Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2009, 4.02010, 4.5 million tons were produced from our property. Western Energy Company, aA subsidiary of Westmoreland Coal Company has two coal leases on the property. Western Energy produces coalCoal is produced by surface dragline mining, and the coal is transported by either truck or beltline to thefour-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 on the following pagebelow shows the location of our properties in Northern Powder River Basin.
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In June 2010, we and International Paper formed BRP. As of December 31, 2010, BRP had acquired, in several stages, approximately 7.35 million mineral acres in 29 states from International Paper. While the vast majority of the 7.35 million acres remain largely undeveloped and underexplored, BRP currently holds 81 revenue generating leases. In addition, a significant number of mineral prospects and deposits with yet undetermined commercial potential have been identified through a variety of efforts including exploration drilling, coring, drill logs, electric logs, inferences derived from published information, geological reports, geological maps, in-house efforts and consulting investigations. These prospects and deposits are not necessarily near-term commercial opportunities due to a variety of factors such as location, market, economic and production uncertainties, but have long-term development potential.
BRP’s assets include approximately 300,000 gross acres of oil and gas mineral rights in Louisiana, of which over 60,000 acres were under lease as of December 31, 2010. In addition, BRP holds a gross production royalty interest on approximately 17,000 mineral acres currently under lease in Louisiana. The remaining oil and gas mineral acreage in Louisiana is not leased, but a significant number of acres are in areas with development potential.
As of December 31, 2010, BRP owned nearly 246,000 gross mineral acres of primarily lignite coal rights in the Gulf Coast region, of which approximately 5,000 acres are leased under three separate leases in Louisiana and Alabama. In addition to the coal rights, BRP held aggregate reserves, including limestone, granite, clay, and sand and gravel reserves, under lease in seven states.
Other mineral rights held by BRP as of December 31, 2010 included coalbed methane rights in four Gulf Coast states, metals rights in three states, approximately 450,000 acres of water rights in East Texas, geothermal rights and royalty interests in the Gulf Coast and Pacific Northwest and carbon sequestration rights primarily in the Gulf Coast region.
The map on the following page illustrates the location of BRP’s current mineral rights.
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Title to Property
Of the approximately 2.12.3 billion tons of proven and probable coal reserves that we owned or controlled as of December 31, 2009,2010, we owned approximately 99% of the reserves in fee. We lease approximately 220 million tons, or less than 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.
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| Item 3. | Legal Proceedings |
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.
| Item 4. |
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PART II
| Item 5. | Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities |
Our common units are listed and traded on the New York Stock Exchange (NYSE) under the symbol “NRP”. As of February 11, 2010,14, 2011, there were approximately 30,70037,800 beneficial and registered holders 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, 20082009 to December 31, 2009,2010, and the quarterly cash distribution declared and paid with respect to each quarter per common unit.
| Cash Distribution History | Cash Distribution History | |||||||||||||||||||||||||||||||||||||||
| Price Range | Per | Record | Payment | Price Range | Per | Record | Payment | |||||||||||||||||||||||||||||||||
| High | Low | Unit | Date | Date | High | Low | Unit | Date | Date | |||||||||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||
| First Quarter | $ | 33.99 | $ | 24.61 | $ | 0.4950 | 05/01/2008 | 05/14/2008 | ||||||||||||||||||||||||||||||||
| Second Quarter | $ | 41.65 | $ | 28.42 | $ | 0.5150 | 08/01/2008 | 08/14/2008 | ||||||||||||||||||||||||||||||||
| Third Quarter | $ | 41.20 | $ | 22.75 | $ | 0.5250 | 11/03/2008 | 11/14/2008 | ||||||||||||||||||||||||||||||||
| Fourth Quarter | $ | 25.99 | $ | 12.66 | $ | 0.5350 | 02/05/2009 | 02/13/2009 | ||||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
| First Quarter | $ | 25.00 | $ | 17.59 | $ | 0.5400 | 05/04/2009 | 05/14/2009 | $ | 25.00 | $ | 17.59 | $ | 0.5400 | 05/04/2009 | 05/14/2009 | ||||||||||||||||||||||||
| Second Quarter | $ | 25.47 | $ | 20.51 | $ | 0.5400 | 08/05/2009 | 08/14/2009 | $ | 25.47 | $ | 20.51 | $ | 0.5400 | 08/05/2009 | 08/14/2009 | ||||||||||||||||||||||||
| Third Quarter | $ | 23.60 | $ | 17.00 | $ | 0.5400 | 11/05/2009 | 11/13/2009 | $ | 23.60 | $ | 17.00 | $ | 0.5400 | 11/05/2009 | 11/13/2009 | ||||||||||||||||||||||||
| Fourth Quarter | $ | 24.81 | $ | 19.50 | $ | 0.5400 | 02/05/2010 | 02/12/2010 | $ | 24.81 | $ | 19.50 | $ | 0.5400 | 02/05/2010 | 02/12/2010 | ||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||
| First Quarter | $ | 27.56 | $ | 21.46 | $ | 0.5400 | 05/05/2010 | 05/14/2010 | ||||||||||||||||||||||||||||||||
| Second Quarter | $ | 26.01 | $ | 18.00 | $ | 0.5400 | 08/05/2010 | 08/13/2010 | ||||||||||||||||||||||||||||||||
| Third Quarter | $ | 27.65 | $ | 22.85 | $ | 0.5400 | 11/05/2010 | 11/12/2010 | ||||||||||||||||||||||||||||||||
| Fourth Quarter | $ | 33.38 | $ | 26.25 | $ | 0.5400 | 02/04/2011 | 02/14/2011 | ||||||||||||||||||||||||||||||||
| Total Quarterly | Marginal Percentage Interest in | |||||||||||||
| Distribution Target | Distributions Paid | |||||||||||||
| Amount | Unitholders | General Partner | Holders of IDRs | |||||||||||
| Minimum Quarterly Distribution | $0.25625 | 98 | % | 2 | % | — | ||||||||
| First Target Distribution | $0.25625 up to $0.28125 | 98 | % | 2 | % | — | ||||||||
| Second Target Distribution | above $0.28125 up to $0.33125 | 85 | % | 2 | % | 13 | % | |||||||
| Third Target Distribution | above $0.33125 up to $0.38125 | 75 | % | 2 | % | 23 | % | |||||||
| Thereafter | above $0.38125 | 50 | % | 2 | % | 48 | % | |||||||
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Cash Distributions to Partners
| General | Limited | Total | General | Limited | Total | |||||||||||||||||||||||||||
| Partner | Partners | IDRs | Distributions | Partner | Partners | IDRs | Distributions | |||||||||||||||||||||||||
| (In thousands) | (In thousands) | |||||||||||||||||||||||||||||||
| 2007 | ||||||||||||||||||||||||||||||||
| Distributions | $ | 2,939 | $ | 118,858 | $ | 25,236 | $ | 147,033 | ||||||||||||||||||||||||
| 2008 | ||||||||||||||||||||||||||||||||
| Distributions | 3,426 | 131,080 | 36,801 | 171,307 | $ | 3,426 | $ | 131,080 | $ | 36,801 | $ | 171,307 | ||||||||||||||||||||
| 2009 | ||||||||||||||||||||||||||||||||
| Distributions | 3,762 | 144,766 | 39,607 | 188,135 | 3,762 | 144,766 | 39,607 | 188,135 | ||||||||||||||||||||||||
| 2010 | ||||||||||||||||||||||||||||||||
| Distributions | 4,197 | 174,709 | 30,943 | 209,849 | ||||||||||||||||||||||||||||
We must distribute all of our cash on hand at the end of each quarter, less cash 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. Provisions of our credit facility and note purchase agreement may restrict our ability to make distributions under certain limited circumstances.
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.
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| Item 6. | Selected Financial Data |
The following table shows selected historical financial data for Natural Resource Partners L.P. for the periods and as of the dates indicated. 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.” These tables should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
NATURAL RESOURCE PARTNERS L.P.
| For the Years Ended December 31, | For the Years Ended December 31, | |||||||||||||||||||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||||||||||||||||||
| (In thousands, except per unit and per ton data) | (In thousands, except per unit and per ton data) | |||||||||||||||||||||||||||||||||||||||
| Income Statement Data: | ||||||||||||||||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||||||||||||||||
| Coal royalties and related revenues | $ | 207,138 | $ | 238,834 | $ | 177,088 | $ | 150,791 | $ | 145,990 | $ | 247,218 | $ | 207,138 | $ | 238,834 | $ | 177,088 | $ | 150,791 | ||||||||||||||||||||
| Coal processing and transportation | 20,190 | 20,437 | 8,808 | 1,452 | — | 24,168 | 20,190 | 20,437 | 8,808 | 1,452 | ||||||||||||||||||||||||||||||
| Aggregate royalties | 5,580 | 9,119 | 7,434 | 538 | — | 4,230 | 5,580 | 9,119 | 7,434 | 538 | ||||||||||||||||||||||||||||||
| Oil and gas royalties | 7,520 | 7,902 | 4,930 | 4,220 | 3,180 | 7,720 | 7,520 | 7,902 | 4,930 | 4,220 | ||||||||||||||||||||||||||||||
| Property taxes | 11,636 | 9,800 | 10,285 | 5,971 | 6,516 | 11,270 | 11,636 | 9,800 | 10,285 | 5,971 | ||||||||||||||||||||||||||||||
| Other | 4,020 | 5,573 | 6,440 | 7,701 | 3,367 | 6,795 | 4,020 | 5,573 | 6,440 | 7,701 | ||||||||||||||||||||||||||||||
| Total revenues | 256,084 | 291,665 | 214,985 | 170,673 | 159,053 | 301,401 | 256,084 | 291,665 | 214,985 | 170,673 | ||||||||||||||||||||||||||||||
| Expenses: | ||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 60,012 | 64,254 | 51,391 | 29,695 | 33,730 | 56,978 | 60,012 | 64,254 | 51,391 | 29,695 | ||||||||||||||||||||||||||||||
| General and administrative | 23,102 | 13,922 | 20,048 | 15,520 | 12,319 | 29,893 | 23,102 | 13,922 | 20,048 | 15,520 | ||||||||||||||||||||||||||||||
| Property, franchise and other taxes | 14,996 | 13,558 | 13,613 | 8,122 | 8,142 | 15,107 | 14,996 | 13,558 | 13,613 | 8,122 | ||||||||||||||||||||||||||||||
| Other | 3,999 | 2,924 | 1,634 | 1,560 | 3,392 | 3,362 | 3,999 | 2,924 | 1,634 | 1,560 | ||||||||||||||||||||||||||||||
| Total expenses | 102,109 | 94,658 | 86,686 | 54,897 | 57,583 | 105,340 | 102,109 | 94,658 | 86,686 | 54,897 | ||||||||||||||||||||||||||||||
| Income from operations | 153,975 | 197,007 | 128,299 | 115,776 | 101,470 | 196,061 | 153,975 | 197,007 | 128,299 | 115,776 | ||||||||||||||||||||||||||||||
| Other, net | (39,895 | ) | (27,001 | ) | (25,800 | ) | (13,686 | ) | (9,631 | ) | ||||||||||||||||||||||||||||||
| Interest expense, net | (41,600 | ) | (39,895 | ) | (27,001 | ) | (25,800 | ) | (13,686 | ) | ||||||||||||||||||||||||||||||
| Net income | $ | 114,080 | $ | 170,006 | $ | 102,499 | $ | 102,090 | $ | 91,839 | $ | 154,461 | $ | 114,080 | $ | 170,006 | $ | 102,499 | $ | 102,090 | ||||||||||||||||||||
| Balance Sheet Data (at period end): | ||||||||||||||||||||||||||||||||||||||||
| Land, equipment, coal and other mineral rights, net | $ | 1,405,083 | $ | 1,174,067 | $ | 1,222,094 | $ | 845,531 | $ | 610,506 | $ | 1,530,458 | $ | 1,405,083 | $ | 1,174,067 | $ | 1,222,094 | $ | 845,531 | ||||||||||||||||||||
| Total assets | 1,523,590 | 1,301,340 | 1,320,031 | 939,493 | 684,996 | 1,664,036 | 1,523,590 | 1,301,340 | 1,320,031 | 939,493 | ||||||||||||||||||||||||||||||
| Long-term debt | 626,587 | 478,822 | 496,057 | 454,291 | 221,950 | 661,070 | 626,587 | 478,822 | 496,057 | 454,291 | ||||||||||||||||||||||||||||||
| Partners’ capital | 765,226 | 743,341 | 744,591 | 435,687 | 425,908 | 825,180 | 765,226 | 743,341 | 744,591 | 435,687 | ||||||||||||||||||||||||||||||
| Other Data: | ||||||||||||||||||||||||||||||||||||||||
| Royalty coal tons produced by lessees | 46,848 | 60,570 | 57,232 | 52,092 | 53,606 | 47,052 | 46,848 | 60,570 | 57,232 | 52,092 | ||||||||||||||||||||||||||||||
| Average gross coal royalty revenue per ton | $ | 4.20 | $ | 3.74 | $ | 2.99 | $ | 2.84 | $ | 2.65 | $ | 4.71 | $ | 4.20 | $ | 3.74 | $ | 2.99 | $ | 2.84 | ||||||||||||||||||||
| Aggregate tons produced by lessee | 3,269 | 4,791 | 5,698 | 412 | — | |||||||||||||||||||||||||||||||||||
| Aggregate tons produced by lessees | 4,365 | 3,269 | 4,791 | 5,698 | 412 | |||||||||||||||||||||||||||||||||||
| Average gross aggregate royalty revenue per ton | $ | 1.30 | $ | 1.31 | $ | 1.19 | $ | 1.11 | — | $ | 1.12 | $ | 1.30 | $ | 1.31 | $ | 1.19 | $ | 1.11 | |||||||||||||||||||||
| Basic and diluted net income per limited partner unit | $ | 1.17 | $ | 1.95 | $ | 1.11 | $ | 1.60 | $ | 1.71 | $ | 1.54 | $ | 1.17 | $ | 1.95 | $ | 1.11 | $ | 1.60 | ||||||||||||||||||||
| Weighted average number of units outstanding | 67,702 | 64,891 | 64,505 | 50,682 | 50,682 | 81,917 | 67,702 | 64,891 | 64,505 | 50,682 | ||||||||||||||||||||||||||||||
| Distributions per limited partner unit | $ | 2.16 | $ | 2.07 | $ | 1.88 | $ | 1.67 | $ | 1.45 | $ | 2.16 | $ | 2.16 | $ | 2.07 | $ | 1.88 | $ | 1.67 | ||||||||||||||||||||
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| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion of the financial condition and results of operations should be read in conjunction with the historical 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 mineral properties in the United States. We own coal propertiesreserves in the three major U.S. coal-producing regions of the United States:regions: Appalachia, the Illinois Basin and the Western United States.States, as well as lignite reserves in the Gulf Coast region. As of December 31, 2009,2010, we owned or controlled approximately 2.12.3 billion tons of proven and probable coal reserves, of which 54% are low sulfur coal. Weand we also owned approximately 130228 million tons of aggregate reserves in Washington, Texas, Arizona and West Virginia.a number of states across the country. We do not operate any mines, but lease our reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell our reserves in exchange for royalty payments.
Our revenue and profitability are dependent on our lessees’ ability to mine and market our 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. In contrast, our aggregate properties are typically mined by regional operators with significant experience and knowledge of the local markets. The aggregates are sold at current market prices, which historically have increased along with the producer price index for sand and gravel at approximately 3.5% per year.gravel. Over the long term, both our coal and aggregate royalty revenues are affected by changes in the market for and the market price of the commodities.
In our royalty business, our lessees generally make payments to us based on the greater of a percentage of the gross sales price or a fixed royalty per ton of coal or aggregates they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time, (usually two to five years)which vary by lease, if sufficient royalties are generated from production in those future periods. We do not recognize these minimum 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 and aggregate royalty revenues, we generated approximately 21%25% of our 20092010 revenues from other sources, as compared to 19%21% in 2008. These2009. The most significant increase in these other sources of revenue occurred due to a substantial minimum royalty paid by Cline with respect to the Colt reserves that was non-recoupable and therefore recognized as revenue. In addition, we received some oil and gas revenues in 2010 related to our BRP joint venture with International Paper. Other sources of revenue include: coal processing and transportation fees; overriding royalties; royalties on oil and gas; wheelage payments; rentals; property tax revenue; minimumsand timber.
Elimination of Incentive Distribution Rights
On September 20, 2010, we eliminated all of the incentive distribution rights (IDRs) held by our general partner and affiliates of the general partner. As consideration for the elimination of the IDRs, we issued 32 million common units to the holders of the IDRs. As of the date of this report, there are 106,027,836 common units outstanding and the general partner has retained its 2% interest in the partnership. Prior to the transaction, the IDRs received as revenue;approximately 24% of the quarterly distribution and timber.48% of any increase in the distribution. Through the elimination of the IDRs, we believe our limited partner unitholders will benefit from our improved cost of capital through:
| • | our enhanced competitive position in the acquisition markets; and | |
| • | increased returns to limited partner unitholders from acquisition and growth projects. |
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While the transaction is expected to be dilutive to cash available for distribution in 2011, we believe that the transaction is in the long-term best interest of the partnership.
Our Current Liquidity Position
As of December 31, 2009,2010, we had $272$206 million in available capacity under our existing credit facility, which does not mature untilmatures in March 2012, as well as approximately $82.6$95.5 million in cash. Following our recent acquisitions of additional coal and aggregate reserves atin the Blue Star mine in Texas and the Deer Run mine in Illinois in January 2010,first two months of 2011, we currently have $229$125 million in available capacity under our credit facility.
Pursuant to the purchase and sale agreement signed in connection with the Colt acquisition, we expect to fund an additional $205$80 million over the next two years, of which approximately $125 million is anticipated to be funded over the next 12 months,year as the operator achieves various development milestones. We anticipate funding thesethe Colt acquisition, as well as any other acquisitions that we consummate, through the use of the available capacity under our credit facility and through the
34
issuance of debtand/or equity in the capital markets. We believe that we have enough liquidity to meet our current capital needs.
In addition, other than a $35 million senior note that matures in 2013, we amortize our long-term debt. Although our annual principal payments will increase significantly beginning in 2013, we have no need to access the capital markets to pay off or refinance any debt obligations other than the one note, and our existing debt will be reduced as the minerals are depleted.
Current Results
Even though coal royalty revenues from our Appalachian properties represented 65%61% of our total revenues in 2009,2010, this percentage has continued to decline as we are diligently working to diversify our holdings by expanding our presence in the Illinois Basin and through additional aggregates and other mineral acquisitions. ThroughOur expansion into Illinois is through the acquisition of reserves by NRP and the development of greenfield mines by Cline. These projects take several years to reach full production, and it is difficult for us to forecast the timing of completion of the projects. To protect against this risk, we are receiving significant minimum royalties with respect to each of the projects. Although minimums provide cash to NRP that can be distributed to our relationshiplimited partners, the minimums are generally not revenue to NRP until recouped through production or at the end of the recoupment period. Thus, to the extent that the development takes longer than anticipated to begin production, it will impact the revenues that we receive in the future.
Operations at the Gatling, West Virginia mine were idled in April 2010 and had not been restarted as of the end of the year. Cline, which operates the mine, has communicated to us that it is continuing to maintain the mine and is currently in discussions with AEP regarding modifications to its existing coal sales contract. In prior periods, efforts by Cline to renegotiate the price for coal from this mine were successful. Cline continues to make its quarterly minimum payments with respect to this mine and has also communicated that it will continue to do so for the remainder of the lease term. The net book value of the assets relating to this operation was $133.6 million as of December 31, 2010. As of the date of this report, we have received $19.0 million in minimum royalties, and contractual quarterly minimums for the remainder of the primary term total $69.7 million. Considering all available information, we have completed an undiscounted cash flow analysis of the assets relating to this operation and determined the undiscounted cash flows exceed those assets’ carrying values. However, if the mine does not become operational in future periods or discussions with potential purchasers of the coal are not successful, the estimated cash flows may change and we may determine that some of the assets associated with the Cline Group, we expectmine have suffered impairment. This decision and an associated impairment charge could have a material adverse impact on our Illinois Basin assets to contribute even more significantly toearnings in the period in which any
36
impairment is recognized, but it would not impact our total revenues in 2010.cash flows from operations or our distributable cash flow.
Political, Legal and Regulatory Environment
The political, legal and regulatory environment is becoming increasingly difficult for the coal industry. In June 2009, the White House Council on Environmental Quality announced a Memorandum of Understanding among the Environmental Protection Agency, or “EPA”, Department of Interior, and the U.S. Army Corps of Engineers concerning the permitting and regulation of coal mines in Appalachia. While the Council described this memorandum as an “unprecedented step[s] to reduce environmental impacts of mountaintop coal mining,” the memorandum broadly applies to all forms of coal mining in Appalachia. The memorandum contemplates both short-term and long-term changes to the process for permitting and regulating coal mines in Appalachia.
These new processes, as yet undefined by EPA, impact only six Appalachian states. In connection with this initiative, the EPA has used its authority to create significant delays in the issuance of new permits and the modification of existing permits. The all-encompassing nature of the changes suggests that implementation of the memorandum will generate continued uncertainty regarding the permitting of coal mines in Appalachia for some time and inevitably will lead, at a minimum, to substantial delays and increased costs.
The United States Congress has been considering multiple bills that would regulate domestic carbon dioxide emissions, but no such bill has yet received sufficient Congressional support for passage into law. The existing Clean Air Act is also a possible mechanism for regulating greenhouse gases. In April 2007,December 2009, the U.S. Supreme Court rendered its decision inMassachusetts v. EPA, finding determined that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Legal challenges to these findings have been asserted, and Congress is considering legislation to delay or repeal EPA’s actions, but we cannot predict the outcome of these efforts. Based on these findings, the EPA has authority under the Clean Air Actbegun adopting and implementing regulations to regulate carbon dioxiderestrict emissions from automobiles and can decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endanger public health or the environment. In response toMassachusetts v. EPA, in July 2008, the EPA issued a notice of proposed rulemaking requesting public comment on the regulation of greenhouse gases or
35
In addition, EPA is under a consent decree by which it must propose by July 2011 and take final action by May 2012 on October 30, 2009, EPA published a final rule in the Federal Register that requires the reporting of greenhouse gas“new source performance standards” to govern GHG emissions from all sectorselectric generating units, certainly including those fired by coal. The decree also represents EPA’s agreement to consider adopting a GHG limitation program governing existing sources, as well, which EPA may attempt to use to establish acap-and-trade-like system on emissions of the American economy, although reporting of emissions from underground coal mines and coal suppliers as originally proposed has been deferred pending further review. On December 15, 2009, EPA published a formal determination that six greenhouse gases, including carbon dioxide and methane, endanger both the public health and welfare of current and future generations. In the same Federal Register rulemaking, EPA found that emission of greenhouse gases from new motor vehicles and their engines contribute to greenhouse gas pollution. AlthoughMassachusetts v. EPA did not involve the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal-fueled power plants, the decision is likely to impact regulation of stationary sources.plants’ GHG emissions.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, primarily through GHG cap and trade programs. Most proposed cap and trade programs work by requiring major sources of emissions, such as coal-fired electric power plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
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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. 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.
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, | For the Years Ended December 31, | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||||||||
| Net cash provided by operating activities | $ | 210,669 | $ | 229,956 | $ | 168,153 | $ | 258,694 | $ | 210,669 | $ | 229,956 | ||||||||||||
| Less scheduled principal payments | (17,235 | ) | (17,234 | ) | (9,350 | ) | (32,234 | ) | (17,235 | ) | (17,234 | ) | ||||||||||||
| Less reserves for future principal payments | (32,235 | ) | (17,235 | ) | (13,388 | ) | (31,699 | ) | (32,235 | ) | (17,235 | ) | ||||||||||||
| Add reserves used for scheduled principal payments | 17,235 | 17,234 | 9,400 | 32,234 | 17,235 | 17,234 | ||||||||||||||||||
| Distributable cash flow | $ | 178,434 | $ | 212,721 | $ | 154,815 | $ | 226,995 | $ | 178,434 | $ | 212,721 | ||||||||||||
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Recent Acquisitions
We are a growth-oriented company and have closedcompleted a number of acquisitions over the last several years. Our most recent acquisitions are briefly described below.
CALX. In February 2011, we acquired approximately 508 acres of mineral and surface rights related to limestone reserves in Livingston County, Kentucky for a purchase price of $16 million, $11 million of which was funded at closing.
BRP LLC. In June 2010, we and International Paper Company formed BRP to own and manage mineral assets previously owned by International Paper. Some of these assets are currently subject to leases, and certain other assets have not yet been developed but are available for future development by the venture. In exchange for a $42.5 million contribution we became the managing and controlling member with a 51% income interest plus a preferential cumulative annual distribution prior to profit sharing. Identified tangible assets in the transaction include oil and gas, coal and aggregate reserves, as well the rights to other unidentified minerals, which may include coal bed methane, geothermal, CO2 sequestration, water rights, precious metals, industrial minerals and base metals. Certain properties, including oil and gas, coal and aggregates, as well as land leased for cell towers, are currently under lease and generating revenues.
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Rockmart Slate. In June 2010, we acquired approximately 100 acres of mineral and surface rights related to slate reserves in Rockmart, Georgia from a local operator for a purchase price of $6.7 million.
Sierra Silica. In April 2010, we acquired the rights to silica reserves on a 1,000 acre property in Northern California from Sierra Silica Resources LLC for $17.0 million.
North American Limestone. In April 2010, we signed an agreement to build and own a fine grind processing facility for high calcium carbonate limestone located in Putnam County, Indiana. We will lease the facility to a local operator. The total cost for the facility is not to exceed $6.5 million. As of our filing date, we have funded approximately $6.2 million of the acquisition.
Northgate-Thayer. In March 2010, we acquired approximately 100 acres of mineral and surface rights related to dolomite limestone reserves in White County, Indiana from a local operator for a purchase price of $7.5 million.
Massey-Override. In March 2010, we acquired from Massey Energy subsidiaries overriding royalty interests in coal reserves located in southern West Virginia and eastern Kentucky. Total consideration for this purchase was $3.0 million.
AzConAgg. In December 2009, we acquired approximately 230 acres of mineral and surface rights related to sand and gravel reserves in southern Arizona from a local operator for $3.75 million.
Colt. In September 2009, we signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the Cline Group, through eightseveral separate transactions for a total purchase price of $255 million. Upon closingAs of the first transaction,December 31, 2010, we paid $10.0 million, funded through our credit facility, andhad acquired approximately 3.350.2 million tons of reserves associated with the initial production from the mine.mine for approximately $105 million. In January 2010,2011, we closed the seconda transaction for $40.0$70.0 million funded through our credit facility, and acquired approximately 19.541.9 million tons of reserves. As of our filing date, we had acquired approximately 92.1 million tons of reserves associated with the initial production from the mine. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.
Blue Star. In July 2009, we acquired approximately 121 acres of limestone reserves in Wise County, Texas from Blue Star Materials, LLC for a purchase price of $24$24.0 million. As of December 31, 2009, we had funded $21.0 million of the acquisition with cash and borrowings under our credit facility. The remaining payment of $3.0 million was funded in January 2010.
Gatling Ohio. In May 2009, we completed the purchase of the membership interests in two companies from Adena Minerals, LLC, an affiliate of the Cline Group. The companies own 51.5 million tons of coal reserves and infrastructure assets at Cline’s Yellowbush Mine located on the Ohio River in Meigs County, Ohio. We issued 4,560,000 common units to Adena Minerals in connection with this acquisition. In addition, the general partner of NRPNatural Resource Partners granted Adena Minerals an additional nine percent interest in the general partner as well as additional incentive distribution rights.partner.
Macoupin. In January 2009, we acquired approximately 82 million tons of 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.
Critical Accounting Policies
Coal and Aggregate Royalties. Coal and aggregate royalty revenues are recognized on the basis of tons of mineral 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 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 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
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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
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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, Depletion and Depletion.Amortization. We depreciate our plant and equipment on a straight line basis over the estimated useful life of the asset. We deplete mineral properties on aunits-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 amortize intangible assets on aunits-of-production basis, unless classified as a temporarily idled asset then a minimum amortization is applied. 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’s (FASB) stock compensation authoritative guidance. This authoritative guidance 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, this authoritative guidance 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 December 2010, the FASB amended how a public entity that enters into a material business combination present comparative financial statements. The amendment specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This amendment also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This amendment is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We adopted this amendment on January 1, 2011 and, therefore, future material acquisitions accounted for as business combinations that are completed by us may be impacted by this amendment.
In December 2010, the FASB modified Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining
40
whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors that would indicate an impairment may exist. The qualitative factors are consistent with the existing guidance, which requires that goodwill of a reporting unit be tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. This amendment is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2010. We do not expect this adoption to have a material impact on the financial statements. However, if future business combinations result in goodwill this guidance may become relevant.
In February 2010, the FASB amended the subsequent events standard, removing the requirement for an SEC filer to disclose the date it issued and revised financial statements. The FASB added that revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. GAAP. We adopted this amendment for the quarter ended March 31, 2010. The adoption did not have a material impact on our disclosures.
In January 2010, the FASB amended fair value disclosure requirements. This amendment requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, seetransfers. See Note 9.8. “Fair Value Measurements” for the definition of Level 1 and Level 2 measurements. The amendment also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs. This amendment is effective for fiscal years beginning after December 15, 2010 and interim periods within those fiscal years. We do not expect this amendment to have an impact on our financial position, results of operations or cash flows.
On January 1, 2009, we adopted new standards for the accounting and reporting of non-controlling interests in a subsidiary. As discussed in Note 3, in connection with the business combination completed in June 2010, we acquired a controlling interest in a newly formed venture. All assets and liabilities of the venture are included in the consolidated balance sheet and the non-controlling interest in the venture is reflected as a component of equity; the revenues and expenses of the venture are reflected in consolidated results of operations with separate disclosure of the earnings or losses allocable to the non-controlling interest.
Other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies are not expected to have a material impact on the financial statements.
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3941
Results of Operations
Summary of 2010 and 2009 Royalties and Production
| For the Years Ended | ||||||||||||||||
| December 31, | Increase | Percentage | ||||||||||||||
| 2010 | 2009 | (Decrease) | Change | |||||||||||||
| (In thousands, except percent and per ton data) | ||||||||||||||||
Coal royalties | ||||||||||||||||
| Appalachia | ||||||||||||||||
| Northern | $ | 18,676 | $ | 14,959 | $ | 3,717 | 25 | % | ||||||||
| Central | 144,934 | 132,543 | 12,391 | 9 | % | |||||||||||
| Southern | 19,405 | 19,382 | 23 | <1 | % | |||||||||||
| Total Appalachia | 183,015 | 166,884 | 16,131 | 10 | % | |||||||||||
| Illinois Basin | 30,210 | 22,019 | 8,191 | 37 | % | |||||||||||
| Northern Powder River Basin | 8,444 | 7,718 | 726 | 9 | % | |||||||||||
| Gulf Coast | 92 | — | 92 | 100 | % | |||||||||||
| Total | $ | 221,761 | $ | 196,621 | $ | 25,140 | 13 | % | ||||||||
Production (tons) | ||||||||||||||||
| Appalachia | ||||||||||||||||
| Northern | 4,900 | 4,943 | (43 | ) | (1 | )% | ||||||||||
| Central | 27,056 | 28,032 | (976 | ) | (3 | )% | ||||||||||
| Southern | 2,824 | 3,233 | (409 | ) | (13 | )% | ||||||||||
| Total Appalachia | 34,780 | 36,208 | (1,428 | ) | (4 | )% | ||||||||||
| Illinois Basin | 7,753 | 6,656 | 1,097 | 16 | % | |||||||||||
| Northern Powder River Basin | 4,467 | 3,984 | 483 | 12 | % | |||||||||||
| Gulf Coast | 52 | — | 52 | 100 | % | |||||||||||
| Total | 47,052 | 46,848 | 204 | <1 | % | |||||||||||
Average gross royalty revenue per ton | ||||||||||||||||
| Appalachia | ||||||||||||||||
| Northern | $ | 3.81 | $ | 3.03 | $ | 0.78 | 26 | % | ||||||||
| Central | 5.36 | 4.73 | 0.63 | 13 | % | |||||||||||
| Southern | 6.87 | 6.00 | 0.87 | 15 | % | |||||||||||
| Total Appalachia | 5.26 | 4.61 | 0.65 | 14 | % | |||||||||||
| Illinois Basin | 3.90 | 3.31 | 0.59 | 18 | % | |||||||||||
| Northern Powder River Basin | 1.89 | 1.94 | (0.05 | ) | (3 | )% | ||||||||||
| Gulf Coast | 1.77 | — | 1.77 | 100 | % | |||||||||||
| Combined average gross royalty revenue per ton | $ | 4.71 | $ | 4.20 | $ | 0.51 | 12 | % | ||||||||
Aggregates | ||||||||||||||||
| Royalty revenues | $ | 4,869 | $ | 4,260 | $ | 609 | 14 | % | ||||||||
| Aggregate Bonus Royalty | $ | (639 | ) | $ | 1,320 | $ | (1,959 | ) | (148 | )% | ||||||
| Production | 4,365 | 3,269 | 1,096 | 34 | % | |||||||||||
| Average gross royalty revenue per ton | $ | 1.12 | $ | 1.30 | $ | (0.18 | ) | (14 | )% | |||||||
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Coal Royalty Revenues and Production
Coal royalty revenues comprised approximately 74% and 77% of our total revenue for the years ended December 31, 2010 and 2009, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Primarily as a result of higher prices being received by our lessees, and the improved royalty rates negotiated on one of our leases, coal royalty revenues increased by $16.1 million in 2010. The 1.4 million ton decline in production was the result of some reductions in production in response to the coal markets, a fire at one of the preparation plants on our property, the temporary idling of two mines and some mines moving their production onto adjacent property.
Illinois Basin. Coal royalty revenues and production on our properties were both higher in 2010. Coal royalty revenues increased by $8.2 million and production increased by 1.1 million tons. The increased production was due to the mine on our Macoupin property operating for the entire year and some of the other mines having increased production. In general, our lessees received higher prices for their production, increasing our royalty per ton.
Northern Powder River Basin. The increase in both coal royalty revenues of $0.7 million and production of 483,000 tons on our Western Energy property was due to the normal variations that occur due to the checkerboard nature of our ownership.
Aggregates Royalty Revenues and Production
We own aggregate reserves in a number of states across the country. For the year ended December 31, 2010, we recognized $4.2 million in royalty revenue from aggregates, which included a reversal of a bonus payment accrual of $0.6 million, under the terms of one of our leases. For the same period for 2009, we recognized royalty revenue from aggregates of $5.6 million, which included bonus revenue of $1.3 million under the same lease. We had production of 4.4 million tons and 3.3 million tons for each of these years.
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Summary of 2009 and 2008 Royalties and Production
| For the Years Ended | For the Years Ended | |||||||||||||||||||||||||||||||
| December 31, | Increase | Percentage | December 31, | Increase | Percentage | |||||||||||||||||||||||||||
| 2009 | 2008 | (Decrease) | Change | 2009 | 2008 | (Decrease) | Change | |||||||||||||||||||||||||
| (In thousands, except percent and per ton data) | (In thousands, except percent and per ton data) | |||||||||||||||||||||||||||||||
Coal royalties | ||||||||||||||||||||||||||||||||
| Appalachia | ||||||||||||||||||||||||||||||||
| Northern | $ | 14,959 | $ | 17,074 | $ | (2,115 | ) | (12 | )% | $ | 14,959 | $ | 17,074 | $ | (2,115 | ) | (12 | )% | ||||||||||||||
| Central | 132,543 | 156,109 | (23,566 | ) | (15 | )% | 132,543 | 156,109 | (23,566 | ) | (15 | )% | ||||||||||||||||||||
| Southern | 19,382 | 19,839 | (457 | ) | (2 | )% | 19,382 | 19,839 | (457 | ) | (2 | )% | ||||||||||||||||||||
| Total Appalachia | 166,884 | 193,022 | (26,138 | ) | (14 | )% | 166,884 | 193,022 | (26,138 | ) | (14 | )% | ||||||||||||||||||||
| Illinois Basin | �� | 22,019 | 21,695 | 324 | 1 | % | 22,019 | 21,695 | 324 | 1 | % | |||||||||||||||||||||
| Northern Powder River Basin | 7,718 | 11,533 | (3,815 | ) | (33 | )% | 7,718 | 11,533 | (3,815 | ) | (33 | )% | ||||||||||||||||||||
| Total | $ | 196,621 | $ | 226,250 | $ | (29,629 | ) | (13 | )% | $ | 196,621 | $ | 226,250 | $ | (29,629 | ) | (13 | )% | ||||||||||||||
Production (tons) | ||||||||||||||||||||||||||||||||
| Appalachia | ||||||||||||||||||||||||||||||||
| Northern | 4,943 | 5,799 | (856 | ) | (15 | )% | 4,943 | 5,799 | (856 | ) | (15 | )% | ||||||||||||||||||||
| Central | 28,032 | 35,967 | (7,935 | ) | (22 | )% | 28,032 | 35,967 | (7,935 | ) | (22 | )% | ||||||||||||||||||||
| Southern | 3,233 | 4,273 | (1,040 | ) | (24 | )% | 3,233 | 4,273 | (1,040 | ) | (24 | )% | ||||||||||||||||||||
| Total Appalachia | 36,208 | 46,039 | (9,831 | ) | (21 | )% | 36,208 | 46,039 | (9,831 | ) | (21 | )% | ||||||||||||||||||||
| Illinois Basin | 6,656 | 8,313 | (1,657 | ) | (20 | )% | 6,656 | 8,313 | (1,657 | ) | (20 | )% | ||||||||||||||||||||
| Northern Powder River Basin | 3,984 | 6,218 | (2,234 | ) | (36 | )% | 3,984 | 6,218 | (2,234 | ) | (36 | )% | ||||||||||||||||||||
| Total | 46,848 | 60,570 | (13,722 | ) | (23 | )% | 46,848 | 60,570 | (13,722 | ) | (23 | )% | ||||||||||||||||||||
Average gross royalty revenue per ton | ||||||||||||||||||||||||||||||||
| Appalachia | ||||||||||||||||||||||||||||||||
| Northern | $ | 3.03 | $ | 2.94 | $ | .09 | 3 | % | $ | 3.03 | $ | 2.94 | $ | 0.09 | 3 | % | ||||||||||||||||
| Central | 4.73 | 4.34 | .39 | 9 | % | 4.73 | 4.34 | 0.39 | 9 | % | ||||||||||||||||||||||
| Southern | 6.00 | 4.64 | 1.36 | 29 | % | 6.00 | 4.64 | 1.36 | 29 | % | ||||||||||||||||||||||
| Total Appalachia | 4.61 | 4.19 | .42 | 10 | % | 4.61 | 4.19 | 0.42 | 10 | % | ||||||||||||||||||||||
| Illinois Basin | 3.31 | 2.61 | .70 | 27 | % | 3.31 | 2.61 | 0.70 | 27 | % | ||||||||||||||||||||||
| Northern Powder River Basin | 1.94 | 1.85 | .09 | 5 | % | 1.94 | 1.85 | 0.09 | 5 | % | ||||||||||||||||||||||
| Combined average gross royalty revenue per ton | $ | 4.20 | $ | 3.74 | $ | .46 | 12 | % | $ | 4.20 | $ | 3.74 | $ | 0.46 | 12 | % | ||||||||||||||||
Aggregates | ||||||||||||||||||||||||||||||||
| Royalty revenues | $ | 4,260 | $ | 6,275 | $ | (2,015 | ) | (32 | )% | $ | 4,260 | $ | 6,275 | $ | (2,015 | ) | (32 | )% | ||||||||||||||
| Aggregate Bonus Royalty | $ | 1,320 | $ | 2,844 | $ | (1,524 | ) | (54 | )% | $ | 1,320 | $ | 2,844 | $ | (1,524 | ) | (54 | )% | ||||||||||||||
| Production | 3,269 | 4,791 | (1,522 | ) | (32 | )% | 3,269 | 4,791 | (1,522 | ) | (32 | )% | ||||||||||||||||||||
| Average gross royalty revenue per ton | $ | 1.30 | $ | 1.31 | $ | (.01 | ) | (1 | )% | $ | 1.30 | $ | 1.31 | $ | (0.01 | ) | (1 | )% | ||||||||||||||
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Coal Royalty Revenues and Production
Coal royalty revenues comprised approximately 77% and 78% of our total revenue for the years ended December 31, 2009 and 2008, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Primarily as result of lower production on our property, coal royalty revenues decreased by $26.1 million in 2009. The decline was the result of some reductions in production in response to the coal
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markets, a fire at one of the preparation plants on our property, and some mines moving their production onto adjacent property. This reduction in production was partially offset by higher per ton royalties.
Illinois Basin. Coal royalty revenues were nearly constant, being only $324,000 higher in 2009 than 2008, although production was 1.7 million tons lower. One mine finished producing on our property in 2009 and moved to adjacent properties. This loss in production was partially offset by production from our Williamson property, which is at a higher royalty rate per ton and therefore we generated more coal royalty revenues.revenues from lower production. Production also began late in the year from our Macoupin property.
Northern Powder River Basin. The decrease in both coal royalty revenues of $3.8 million and production of 2.2 million tons on our Western Energy property was due to the normal variations that occur due to the checkerboard nature of our ownership.
Aggregates Royalty Revenues and Production
We own aggregate reserves located in Washington, Arizona, Texas and West Virginia. For the years ended December 31, 2009 and 2008, we recorded $5.6 million and $9.1 million, respectively, in royalty revenues from aggregates, and had production of 3.3 million tons and 4.8 million tons for each of these years. Nearly all of this production and revenue is attributable to the aggregate reserves in DuPont, Washington. In 2009 we receivedrecognized a bonus royalty payment of $1.3 million from the Washington reserves compared to a $2.8 million payment in 2008. The reduction in tonnage and royalty is primarily attributed to lower demand caused by the poorer economic conditions in 2009.
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| 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 | % | ||||||||
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Other Operating Results
Coal Processing and Transportation Revenues. We generated $9.6 million, $7.7 million $8.8 million and $4.8$8.8 million in processing revenues for the years ended December 31, 2010, 2009 2008 and 2007.2008. 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. The increase in processing revenues for the year ended December 31, 2010 is primarily due to higher volumes at higher prices. The increase in 2010 also reflects the addition of the preparation plant at Macoupin being online for a full year. The decrease in 2009 reflects the lower demand due to the depressed economy.
In addition to our preparation plants, we own coal handling and transportation infrastructure in West Virginia, Ohio and Illinois. In contrast to our typical royalty structure, we receive a fixed rate per ton for coal transported over these facilities. For the assets other than our loadout facility at the Shay No. 1 mine in Illinois, 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 $14.6 million, $12.5 million $11.7 million and $4.0$11.7 million for the years ended December 31, 2010, 2009 2008 and 2007,2008, respectively. Production increased during the last half of 2008 and all of 2009 due to the longwall at our Williamson property coming online in March 2008. Our Macoupin property coming online late in 2009 and operating a full year in 2010 also contributed to the increase late in 2009 and in 2010.
Additional Revenues. In addition to coal royalties, aggregate royalties, coal processing and transportation revenues, we generated approximately 17%, 13% and 12% of our revenues from other sources for the years ended December 31, 2010, 2009 and 2008, and 2007.respectively. These other sources include: oil and gas royalties, property taxes, minimums recognized, overriding royalties, timber, rentals and wheelage. Minimums recognized as revenues increased in 2010 by $12.9 million primarily due to a non-recoupable minimum on our Colt reserves received in 2010. In future years, the minimums received with respect to this property will be reflected as revenue only when recouped through production.
Operating costs and expenses. Included in total expenses are:
| • | Depreciation, depletion and amortization of $57.0 million, $60.0 million |
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| accounting policy for contract amortization during 2010. Depletion decreased in 2009 from 2008 as a result of lower total production for |
| • | General and administrative expenses of $29.9 million, $23.1 million | |
| • | Property, franchise and other taxes |
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Interest Expense. Interest expense was higher$41.6 million, $40.1 million and $28.4 million for the year ended December 31, 2009 when compared to the years ended December 31, 2010, 2009 and 2008, and 2007 duerespectively. Due to additional debt incurred to fund acquisitions andas well as higher interest rates.rates on the senior notes issued in 2009, interest expense has increased since 2008.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
We satisfy our working capital requirements with cash generated from operations. Since our initial public offering, we have financed our property acquisitions with available cash, borrowings under our revolving credit facility, and the issuance of our senior notes and additional units. While our ability to satisfy our debt service obligations and pay distributions to our unitholders depends in large part on our future operating performance, our ability to make acquisitions will depend on prevailing economic conditions in the financial markets as well as the coal industry and other factors, some of which are beyond our control. For a more complete discussion of factors that will affect cash flow we generate from operations, please read “Item 1A. Risk Factors”. Our capital expenditures, other than for acquisitions, have historically been minimal.
Our credit facility does not expire untilmatures in March 2012, and our credit ratios are within our debt covenants for both our credit facility and our outstanding senior notes. In addition, we are amortizing substantially all of our long-term debtsenior notes and have no immediate need to refinance. For a more complete discussion of factors that will affect our liquidity, please read “Item 1A. Risk Factors”. During 2009,2010, we continued to review our banking relationships and our internal policies regarding deposit concentrations with specific attention to effectively managing risk in the current banking environment. Following our second acquisitionacquisitions of coal and aggregate reserves atin the Deer Run mine and our final payment on the Blue Star reserve acquisition in January 2010,first two months of 2011, we had $229$125 million in available capacity under theour credit facility. We also had approximately $83$95.5 million of cash available at the end of the year.
Net cash provided by operations for the years ended December 31, 2010, 2009 and 2008 and 2007 was $258.7, $210.7 million and $230.0 million, and $168.2 million, respectively. AThe most significant portion of our cash provided by operations is generated from coal royalty revenues.
Net cash used in investing activities for the years December 31, 2010, 2009 and 2008 and 2007 was $170.8, $119.9 million $9.8 million and $79.6$9.8 million, respectively. In each of those years, substantially all of our investing activities consisted of acquiring coal reserves, plant and equipment and other mineral rights. In 2007, we sold surface acreage in Wise County, Virginia for gross proceeds of $1.4 million.
Net cash used for financing activities for the years ended December 31, 2010, 2009 and 2008 and 2007 was $75.0 million, $98.1 million $188.5 million and $96.2$188.5 million, respectively. We had proceeds from loans of $331.0$140.0 million and $285.4$331.0 million for the years ended December 31, 20092010 and 2007. The proceeds were offset by repayment of credit facility borrowings of $151.0 million and $226.4 million for the years ended December 31, 2009 and 2007, respectively.2009. We did not receive any proceeds from loans for the year ended December 31, 2008. We had proceeds from the issuance of units of $110.4 million for the year ended December 31, 2010. We did not receive any proceeds from the issuance of units for the years ended December 31, 2009 and 2008. The proceeds were offset by repayments of credit facility borrowings of $74.0 million and $151.0 million for the years ended December 31, 2010 and 2009,
46
respectively. We also made $32.2 million, $17.2 million and $17.2 million in principal payments on our senior notes for the years ended December 31, 2010, 2009 and 2008, respectively, and $9.5 million for the year ended December 31, 2007. Proceeds for the year ended December 31, 2009respectively. The proceeds were also offset by retirement of purchase obligations related to the purchase of reserves and infrastructure of $72.0 million. We paid distributions of $188.1 million, $171.3$9.2 million and $147.0$72.0 million for the years ended December 31, 2009, 20082010 and 2007,2009, respectively. We made $9.4paid distributions of $209.8 million, in principal payments on our senior notes in 2007. In 2007, as a part of$188.1 million and $171.3 million for the Dingess-Rumyears ended December 31, 2010, 2009 and Mettiki acquisitions we received a $2.6 million cash contribution from our general partner to maintain its 2% interest.2008, respectively.
Contractual Obligations and Commercial Commitments
44
Credit Facility. We have a $300 million revolving credit facility, and at December 31, 2009as of the date of this report we had approximately $272$125 million available to us under the facility. Under an accordion feature in the credit facility, we may request our lenders to increase their aggregate commitment to a maximum of $450 million on the same terms. However, under current market conditions, we cannot be certain that our lenders will elect to participate in the accordion feature. To the extent the lenders decline to participate, we may attemptelect to bring new lenders into the facility, but we cannot make any assurance that any new lenders would elect to participate or that the excessadditional credit capacity will be available to us at allon existing or on the existingcomparable terms.
During 2010, our borrowings and repayments under our credit facility were as follows:
| First | Second | Third | Fourth | |||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
| Outstanding balance, beginning of period | $ | 28,000 | $ | 74,000 | $ | 35,000 | $ | 39,000 | ||||||||
| Borrowings under credit facility | 46,000 | 35,000 | 4,000 | 55,000 | ||||||||||||
| Less: Repayments under credit facility | — | (74,000 | ) | — | — | |||||||||||
| Outstanding balance, ending period | $ | 74,000 | $ | 35,000 | $ | 39,000 | $ | 94,000 | ||||||||
Our obligations under the credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under the revolving credit facility bears interest, at our option, at either:
| • | the higher of the federal funds rate plus an applicable margin ranging from 0% to 0.50% or the prime rate as announced by the agent bank; or | |
| • | at a rate equal to LIBOR plus an applicable margin ranging from 0.45% to 1.50%. |
We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.10% to 0.30% per annum.
The credit agreement contains covenants requiring us to maintain:
| • | a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and | |
| • | a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters. |
Senior Notes. NRP Operating LLC issued the senior notes listed below under a note purchase agreement.agreement as supplemented from time to time. The senior notes are unsecured but are guaranteed by our operating subsidiaries. We may prepay the senior notes at any time together with a make-whole amount (as defined in the note purchase agreement). If any event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies.
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The senior note purchase agreement contains covenants requiring our operating subsidiary to:
| • | Maintain a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters; | |
| • | not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and | |
| • | maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0. |
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In March 2009, we issued $150 million of 8.38% notes maturing March 25, 2019 and $50 million of 8.92% notes maturing March 2024. These senior notes provide that in the event that our leverage ratio exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.
Long-Term Debt
At December 31, 2010, our debt consisted of:
| • | $94.0 million of our $300 million floating rate revolving credit facility, due March 2012; | |
| • | $35.0 million of 5.55% senior notes due 2013; | |
| • | $37.7 million of 4.91% senior notes due 2018; | |
| • | $150.0 million of 8.38% senior notes due 2019; | |
| • | $76.9 million of 5.05% senior notes due 2020; | |
| • | $2.1 million of 5.31% utility local improvement obligation due 2021; | |
| • | $36.9 million of 5.55% senior notes due 2023; | |
| • | $210.0 million of 5.82% senior notes due 2024; and | |
| • | $50.0 million of 8.92% senior notes due 2024. |
Other than the 5.55% senior notes due 2013, which have only semi-annual interest payments, all of our senior notes require annual principal payments in addition to semi-annual interest payments. The scheduled principal payments on the 8.38% senior notes due 2019 do not begin until March 2013, and the scheduled principal payments on the 8.92% senior notes due 2024 do not begin until March 2014. We also make annual principal and interest payments on the utility local improvement obligation.
The following table reflects our long-term non-cancelable contractual obligations as of December 31, 20092010 (in millions):
| Payments Due by Period | ||||||||||||||||||||||||||||
Contractual Obligations | Total | 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter | |||||||||||||||||||||
| Long-term debt (including current maturities)(1) | $ | 658.8 | $ | 32.2 | $ | 31.5 | $ | 58.8 | $ | 87.2 | $ | 56.2 | $ | 392.9 | ||||||||||||||
| Pending acquisitions(2) | 248.0 | 168.0 | 65.0 | 15.0 | — | — | — | |||||||||||||||||||||
| Rental lease(3) | 5.3 | 0.5 | 0.5 | 0.5 | 0.5 | 0.5 | 2.8 | |||||||||||||||||||||
| Total | $ | 912.1 | $ | 200.7 | $ | 97.0 | $ | 74.3 | $ | 87.7 | $ | 56.7 | $ | 395.7 | ||||||||||||||
| Payments Due by Period | ||||||||||||||||||||||||||||
| Contractual Obligations | Total | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | |||||||||||||||||||||
| Long-term debt principal payments (including current maturities)(1) | $ | 692.6 | $ | 31.5 | $ | 124.8 | $ | 87.2 | $ | 56.2 | $ | 56.2 | $ | 336.7 | ||||||||||||||
| Long-term debt interest payments(2) | 239.5 | 38.4 | 36.7 | 33.2 | 28.5 | 24.7 | 78.0 | |||||||||||||||||||||
| Pending acquisitions(3) | 150.0 | 110.0 | 40.0 | — | — | — | — | |||||||||||||||||||||
| Rental leases(4) | 4.3 | 0.6 | 0.6 | 0.5 | 0.5 | 0.5 | 1.6 | |||||||||||||||||||||
| Total | $ | 1,086.4 | $ | 180.5 | $ | 202.1 | $ | 120.9 | $ | 85.2 | $ | 81.4 | $ | 416.30 | ||||||||||||||
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| (1) | The amounts indicated in the table include principal | |
| (2) | The amounts indicated in the table include | |
| (3) | The amounts indicated in the table include $150.0 million related to the future anticipated acquisitions with Colt | |
| On January 1, 2009, we entered into a ten year lease agreement for the rental of office space from Western Pocahontas Properties Limited Partnership. The rental obligations from this lease are included in the table above. |
Shelf Registration Statement
In addition to our credit facility, on February 27, 2009 we filed an automatically effective shelf registration statement onForm S-3 with the SECSecurities and Exchange Commission that is available for registered offerings of common units and debt securities. The amounts, prices and timing of the issuance and sale of any equity or debt securities will depend on market conditions, our capital requirements and compliance with our credit facility and senior notes.
Off-Balance Sheet Transactions
We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the years ended December 31, 2010, 2009 2008 and 2007.2008.
Environmental
The operations our lessees conduct on our properties are subject to federal and state environmental laws and regulations. As an owner of surface interests in some properties, we may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of our coal leases
46
require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify us against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because we have no employees, employees of Western Pocahontas Properties Limited Partnership make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. We believe that our lessees will be able to comply with existing regulations and do not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on our financial condition or results of operations. We have neither incurred, nor are aware of, any material environmental charges imposed on us related to our properties for the period ended December 31, 2009.2010. We are not associated with any environmental contamination that may require remediation costs. However, our lessees do conduct reclamation work on the properties under lease to them. Because we are not the permittee of the mines being reclaimed, we are not responsible for the costs associated with these reclamation operations. In addition, West Virginia has established a fund to satisfy any shortfall in reclamation obligations.
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Related Party Transactions
Partnership Agreement
Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with ourthe partnership agreement, we reimburse our general partner and its affiliates for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to unitholders.
The reimbursements to our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $6.8 million in 2009, $5.6 million in 2008 and $5.0 million in 2007. are as follows:
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Reimbursement for services | $ | 7,358 | $ | 6,822 | $ | 5,557 | ||||||
For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement.”
Transactions with Cline Affiliates
Various companies controlled by Chris Cline lease coal reserves from NRP, and we provide coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in NRP’sour general partner, and in the incentive distribution rights of NRP, as well as 13,510,07221,017,441 common units. At December 31, 2009,2010, we had accounts receivable totaling $4.0$6.5 million from Cline affiliates. ForRevenues from the years endedCline affiliates are as follows:
| For the Year Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Coal royalty revenues | $ | 32,407 | $ | 23,325 | $ | 19,255 | ||||||
| Coal processing fees | 1,337 | 193 | — | |||||||||
| Transportation fees | 14,324 | 11,495 | 6,895 | |||||||||
| Minimums recognized as revenue | 12,400 | — | — | |||||||||
| Override revenue | 1,904 | 2,356 | 1,788 | |||||||||
| $ | 62,372 | $ | 37,369 | $ | 27,938 | |||||||
As of December 31, 2009, 2008 and 2007,2010, we had total revenue of $37.4received $47.0 million $27.9 million and $7.5 million, respectively, from these companies. In addition, we have received $16.2 million in advance minimum royalty payments that have not been recouped.recouped by Cline affiliates, of which $22.8 million was received in the current year.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, wethe Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in NRP’s conflicts policy.
A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s5-person board of directors. WeNRP currently havehas a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. We will ownNRP owns and leaseleases the plants to
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Taggart Global, which will design, builddesigns, builds and operateoperates the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. To date, we have acquired four facilities under this agreement with Taggart with a total cost of $46.6 million. For the years ended December 31, 2009, 2008 and 2007, we received total revenue of $3.9 million and $5.0 million and $2.7 million, respectively,Revenues from Taggart. Taggart are as follows:
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Coal processing revenue | $ | 5,874 | $ | 3,872 | $ | 4,971 | ||||||
At December 31, 2009,2010, we had accounts receivable totaling $0.2$1.3 million from Taggart.
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| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Coal royalty revenues | $ | 1,545 | $ | 1,560 | $ | 1,445 | ||||||
NRP also had accounts receivable totaling $0.1 million from Kopper-Glo.Kopper-Glo at December 31, 2010.
Office Building in Huntington, West Virginia
| Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
We are exposed to market risk, which includes adverse changes in commodity prices and interest rates.
Commodity Price Risk
We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. We estimate that over 80% of our coal is currently sold by our lessees under coal supply contracts that have terms of one year or more. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees’ failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees’ operations and adversely affect our coal royalty revenues. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices.
Interest Rate Risk
Our exposure to changes in interest rates results from our current borrowings under our credit facility, which are subject to variable interest rates based upon LIBOR or the federal funds rate plus an applicable margin. Management monitors interest rates and may enter into interest rate instruments to protect against increased borrowing costs. At December 31, 2009,2010, we had $28$94 million outstanding in variable interest debt. If interest rates were to increase by 1%, annual interest expense would increase $280,000,$940,000, assuming the same principal amount remained outstanding during the year.
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| Item 8. | Financial Statements and Supplementary Data |
INDEX TO FINANCIAL STATEMENTS
| Page | ||||
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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Natural Resource Partners L.P.
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 20092010 and 2008,2009, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009.2010. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 20092010 and 2008,2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2009,2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 201028, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 26, 201028, 2011
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NATURAL RESOURCE PARTNERS L.P.
| December 31, | December 31, | |||||||
| 2009 | 2008 | |||||||
| (In thousands, except for unit information) | ||||||||
ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 82,634 | $ | 89,928 | ||||
| Accounts receivable, net of allowance for doubtful accounts | 27,141 | 31,883 | ||||||
| Accounts receivable — affiliates | 4,342 | 1,351 | ||||||
| Other | 930 | 934 | ||||||
| Total current assets | 115,047 | 124,096 | ||||||
| Land | 24,343 | 24,343 | ||||||
| Plant and equipment, net | 64,267 | 67,204 | ||||||
| Coal and other mineral rights, net | 1,151,313 | 979,692 | ||||||
| Intangible assets, net | 165,160 | 102,828 | ||||||
| Loan financing costs, net | 2,891 | 2,679 | ||||||
| Other assets, net | 569 | 498 | ||||||
| Total assets | $ | 1,523,590 | $ | 1,301,340 | ||||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
| Current liabilities: | ||||||||
| Accounts payable and accrued liabilities | $ | 914 | $ | 861 | ||||
| Accounts payable — affiliates | 179 | 365 | ||||||
| Obligation related to acquisition | 2,969 | — | ||||||
| Current portion of long-term debt | 32,235 | 17,235 | ||||||
| Accrued incentive plan expenses — current portion | 4,627 | 3,179 | ||||||
| Property, franchise and other taxes payable | 6,164 | 6,122 | ||||||
| Accrued interest | 10,300 | 6,419 | ||||||
| Total current liabilities | 57,388 | 34,181 | ||||||
| Deferred revenue | 67,018 | 40,754 | ||||||
| Accrued incentive plan expenses | 7,371 | 4,242 | ||||||
| Long-term debt | 626,587 | 478,822 | ||||||
| Partners’ capital: | ||||||||
| Common units outstanding: (69,451,136 in 2009, 64,891,136 in 2008) | 747,437 | 719,341 | ||||||
| General partner’s interest | 13,409 | 13,579 | ||||||
| Holders of incentive distribution rights | 4,977 | 11,069 | ||||||
| Accumulated other comprehensive loss | (597 | ) | (648 | ) | ||||
| Total partners’ capital | 765,226 | 743,341 | ||||||
| Total liabilities and partners’ capital | $ | 1,523,590 | $ | 1,301,340 | ||||
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| For the Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands, except per unit data) | ||||||||||||
| Revenues: | ||||||||||||
| Coal royalties | $ | 196,621 | $ | 226,250 | $ | 171,343 | ||||||
| Aggregate royalties | 5,580 | 9,119 | 7,434 | |||||||||
| Coal processing fees | 7,673 | 8,781 | 4,824 | |||||||||
| Transportation fees | 12,517 | 11,656 | 3,984 | |||||||||
| Oil and gas royalties | 7,520 | 7,902 | 4,930 | |||||||||
| Property taxes | 11,636 | 9,800 | 10,285 | |||||||||
| Minimums recognized as revenue | 1,266 | 1,257 | 1,951 | |||||||||
| Override royalties | 9,251 | 11,327 | 3,794 | |||||||||
| Other | 4,020 | 5,573 | 6,440 | |||||||||
| Total revenues | 256,084 | 291,665 | 214,985 | |||||||||
| Operating costs and expenses: | ||||||||||||
| Depreciation, depletion and amortization | 60,012 | 64,254 | 51,391 | |||||||||
| General and administrative | 23,102 | 13,922 | 20,048 | |||||||||
| Property, franchise and other taxes | 14,996 | 13,558 | 13,613 | |||||||||
| Transportation costs | 1,611 | 1,416 | 298 | |||||||||
| Coal royalty and override payments | 2,388 | 1,508 | 1,336 | |||||||||
| Total operating costs and expenses | 102,109 | 94,658 | 86,686 | |||||||||
| Income from operations | 153,975 | 197,007 | 128,299 | |||||||||
| Other income (expense) | ||||||||||||
| Interest expense | (40,108 | ) | (28,356 | ) | (28,690 | ) | ||||||
| Interest income | 213 | 1,355 | 2,890 | |||||||||
| Net income | $ | 114,080 | $ | 170,006 | $ | 102,499 | ||||||
| Net income attributable to: | ||||||||||||
| General partner | $ | 1,611 | $ | 2,602 | $ | 1,489 | ||||||
| Holders of incentive distribution rights | $ | 33,515 | $ | 39,914 | $ | 28,079 | ||||||
| Limited partners | $ | 78,954 | $ | 127,490 | $ | 72,931 | ||||||
| Basic and diluted net income per limited partner unit | $ | 1.17 | $ | 1.95 | $ | 1.11 | ||||||
| Weighted average number of units outstanding | 67,702 | 64,891 | 64,505 | |||||||||
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| Holders | ||||||||||||||||||||||||
| of Incentive | Accumulated | |||||||||||||||||||||||
| General | Distribution | Other | ||||||||||||||||||||||
| Common Units | Partner | Rights | Comprehensive | |||||||||||||||||||||
| Units | Amounts | Amounts | Amounts | Income (Loss) | Total | |||||||||||||||||||
| (In thousands, except unit data) | ||||||||||||||||||||||||
| Balance at December 31, 2006 | 50,681,064 | $ | 422,536 | $ | 8,791 | $ | 5,111 | $ | (751 | ) | $ | 435,687 | ||||||||||||
| Issuance of units for acquisitions | 14,210,072 | 346,319 | 4,422 | — | — | 350,741 | ||||||||||||||||||
| Capital contribution | — | — | 2,645 | — | — | 2,645 | ||||||||||||||||||
| Distributions to unitholders | — | (118,855 | ) | (2,942 | ) | (25,236 | ) | — | (147,033 | ) | ||||||||||||||
| Net income for the year ended | ||||||||||||||||||||||||
| December 31, 2007 | — | 72,931 | 1,489 | 28,079 | — | 102,499 | ||||||||||||||||||
| Loss on interest hedge | — | — | — | — | 52 | 52 | ||||||||||||||||||
| Comprehensive income | — | — | — | — | 52 | 102,551 | ||||||||||||||||||
| Balance at December 31, 2007 | 64,891,136 | $ | 722,931 | $ | 14,405 | 7,954 | $ | (699 | ) | $ | 744,591 | |||||||||||||
| Distributions to unitholders | — | (131,080 | ) | (3,428 | ) | (36,799 | ) | — | (171,307 | ) | ||||||||||||||
| Net income for the year ended | ||||||||||||||||||||||||
| December 31, 2008 | — | 127,490 | 2,602 | 39,914 | — | 170,006 | ||||||||||||||||||
| Loss on interest hedge | — | — | — | — | 51 | 51 | ||||||||||||||||||
| Comprehensive income | — | — | — | — | 51 | 170,057 | ||||||||||||||||||
| Balance at December 31, 2008 | 64,891,136 | $ | 719,341 | $ | 13,579 | $ | 11,069 | $ | (648 | ) | $ | 743,341 | ||||||||||||
| Distributions to unitholders | — | (144,766 | ) | $ | (3,762 | ) | (39,607 | ) | — | (188,135 | ) | |||||||||||||
| Issuance of units for acquisitions, net | 4,560,000 | 93,908 | 1,981 | — | — | 95,889 | ||||||||||||||||||
| Net income for the year ended | ||||||||||||||||||||||||
| December 31, 2009 | — | 78,954 | 1,611 | 33,515 | — | 114,080 | ||||||||||||||||||
| Loss on interest hedge | — | — | — | — | 51 | 51 | ||||||||||||||||||
| Comprehensive income | — | — | — | — | 51 | 114,131 | ||||||||||||||||||
| Balance at December 31, 2009 | 69,451,136 | $ | 747,437 | $ | 13,409 | $ | 4,977 | $ | (597 | ) | $ | 765,226 | ||||||||||||
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| For the Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
| Cash flows from operating activities: | ||||||||||||
| Net income | $ | 114,080 | $ | 170,006 | $ | 102,499 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
| Depreciation, depletion and amortization | 60,012 | 64,254 | 51,391 | |||||||||
| Non-cash interest charge | 1,463 | 278 | 443 | |||||||||
| Gain(loss) on sale of assets | — | 33 | (1,236 | ) | ||||||||
| Change in operating assets and liabilities: | ||||||||||||
| Accounts receivable | 581 | (4,586 | ) | (5,270 | ) | |||||||
| Other assets | (67 | ) | 178 | 178 | ||||||||
| Accounts payable and accrued liabilities | (133 | ) | (1,484 | ) | (464 | ) | ||||||
| Accrued interest | 3,850 | 143 | 2,430 | |||||||||
| Deferred revenue | 26,264 | 4,468 | 15,632 | |||||||||
| Accrued incentive plan expenses | 4,577 | (3,041 | ) | 465 | ||||||||
| Property, franchise and other taxes payable | 42 | (293 | ) | 2,085 | ||||||||
| Net cash provided by operating activities | 210,669 | 229,956 | 168,153 | |||||||||
| Cash flows from investing activities: | ||||||||||||
| Acquisition of land, coal, other mineral rights and related intangibles | (118,754 | ) | (5,500 | ) | (58,124 | ) | ||||||
| Acquisition or construction of plant and equipment | (1,157 | ) | (10,568 | ) | (16,695 | ) | ||||||
| Proceeds from sale of assets | — | — | 1,425 | |||||||||
| Change in restricted accounts | — | 6,240 | (6,240 | ) | ||||||||
| Net cash used in investing activities | (119,911 | ) | (9,828 | ) | (79,634 | ) | ||||||
| Cash flows from financing activities: | ||||||||||||
| Proceeds from loans | 331,000 | — | 285,400 | |||||||||
| Deferred financing costs | (661 | ) | — | (1,292 | ) | |||||||
| Repayments of loans | (168,235 | ) | (17,234 | ) | (235,942 | ) | ||||||
| Retirement of purchase obligation related to reserves and infrastructure | (72,000 | ) | — | — | ||||||||
| Costs associated with unit issuance | (21 | ) | — | — | ||||||||
| Distributions to partners | (188,135 | ) | (171,307 | ) | (147,033 | ) | ||||||
| Contributions by general partner | — | — | 2,645 | |||||||||
| Net cash used in financing activities | (98,052 | ) | (188,541 | ) | (96,222 | ) | ||||||
| Net increase (decrease) in cash and cash equivalents | (7,294 | ) | 31,587 | (7,703 | ) | |||||||
| Cash and cash equivalents at beginning of period | 89,928 | 58,341 | 66,044 | |||||||||
| Cash and cash equivalents at end of period | $ | 82,634 | $ | 89,928 | $ | 58,341 | ||||||
| Supplemental cash flow information: | ||||||||||||
| Cash paid during the period for interest | $ | 34,710 | $ | 27,735 | $ | 25,771 | ||||||
| Non-cash investing activities: | ||||||||||||
| Equity issued for acquisitions | $ | 95,910 | $ | — | $ | 346,319 | ||||||
| Assets contributed by general partner for acquisitions | 1,981 | — | 4,422 | |||||||||
| Liability assumed from acquisitions | 1,170 | — | 1,989 | |||||||||
| Purchase obligation related to reserve and infrastructure acquisition | 74,022 | — | — | |||||||||
| December 31, | December 31, | |||||||
| 2010 | 2009 | |||||||
| (In thousands, except for unit information) | ||||||||
ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 95,506 | $ | 82,634 | ||||
| Accounts receivable, net of allowance for doubtful accounts | 26,195 | 27,141 | ||||||
| Accounts receivable — affiliates | 7,915 | 4,342 | ||||||
| Other | 910 | 930 | ||||||
| Total current assets | 130,526 | 115,047 | ||||||
| Land | 24,543 | 24,343 | ||||||
| Plant and equipment, net | 62,348 | 64,351 | ||||||
| Coal and other mineral rights, net | 1,281,636 | 1,151,835 | ||||||
| Intangible assets, net | 161,931 | 164,554 | ||||||
| Loan financing costs, net | 2,436 | 2,891 | ||||||
| Other assets, net | 616 | 569 | ||||||
| Total assets | $ | 1,664,036 | $ | 1,523,590 | ||||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
| Current liabilities: | ||||||||
| Accounts payable and accrued liabilities | $ | 1,388 | $ | 914 | ||||
| Accounts payable — affiliates | 499 | 179 | ||||||
| Obligation related to acquisition | — | 2,969 | ||||||
| Current portion of long-term debt | 31,518 | 32,235 | ||||||
| Accrued incentive plan expenses — current portion | 6,788 | 4,627 | ||||||
| Property, franchise and other taxes payable | 6,926 | 6,164 | ||||||
| Accrued interest | 9,811 | 10,300 | ||||||
| Total current liabilities | 56,930 | 57,388 | ||||||
| Deferred revenue | 109,509 | 67,018 | ||||||
| Accrued incentive plan expenses | 11,347 | 7,371 | ||||||
| Long-term debt | 661,070 | 626,587 | ||||||
| Partners’ capital: | ||||||||
| Common units outstanding: (106,027,836 in 2010, 69,451,136 in 2009) | 806,529 | 747,437 | ||||||
| General partner’s interest | 14,132 | 13,409 | ||||||
| Holders of incentive distribution rights | — | 4,977 | ||||||
| Non-controlling interest | 5,065 | — | ||||||
| Accumulated other comprehensive loss | (546 | ) | (597 | ) | ||||
| Total partners’ capital | 825,180 | 765,226 | ||||||
| Total liabilities and partners’ capital | $ | 1,664,036 | $ | 1,523,590 | ||||
The accompanying notes are an integral part of these financial statements.
54
NATURAL RESOURCE PARTNERS L.P.
| For the Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands, except per unit data) | ||||||||||||
| Revenues: | ||||||||||||
| Coal royalties | $ | 221,761 | $ | 196,621 | $ | 226,250 | ||||||
| Aggregate royalties | 4,230 | 5,580 | 9,119 | |||||||||
| Coal processing fees | 9,604 | 7,673 | 8,781 | |||||||||
| Transportation fees | 14,564 | 12,517 | 11,656 | |||||||||
| Oil and gas royalties | 7,720 | 7,520 | 7,902 | |||||||||
| Property taxes | 11,270 | 11,636 | 9,800 | |||||||||
| Minimums recognized as revenue | 14,199 | 1,266 | 1,257 | |||||||||
| Override royalties | 11,258 | 9,251 | 11,327 | |||||||||
| Other | 6,795 | 4,020 | 5,573 | |||||||||
| Total revenues | 301,401 | 256,084 | 291,665 | |||||||||
| Operating costs and expenses: | ||||||||||||
| Depreciation, depletion and amortization | 56,978 | 60,012 | 64,254 | |||||||||
| General and administrative | 29,893 | 23,102 | 13,922 | |||||||||
| Property, franchise and other taxes | 15,107 | 14,996 | 13,558 | |||||||||
| Transportation costs | 1,864 | 1,611 | 1,416 | |||||||||
| Coal royalty and override payments | 1,498 | 2,388 | 1,508 | |||||||||
| Total operating costs and expenses | 105,340 | 102,109 | 94,658 | |||||||||
| Income from operations | 196,061 | 153,975 | 197,007 | |||||||||
| Other income (expense) | ||||||||||||
| Interest expense | (41,635 | ) | (40,108 | ) | (28,356 | ) | ||||||
| Interest income | 35 | 213 | 1,355 | |||||||||
| Income before non-controlling interest | 154,461 | 114,080 | 170,006 | |||||||||
| Non-controlling interest | — | — | — | |||||||||
| Net income | $ | 154,461 | $ | 114,080 | $ | 170,006 | ||||||
| Net income attributable to: | ||||||||||||
| General partner | $ | 2,570 | $ | 1,611 | $ | 2,602 | ||||||
| Holders of incentive distribution rights | $ | 25,966 | $ | 33,515 | $ | 39,914 | ||||||
| Limited partners | $ | 125,925 | $ | 78,954 | $ | 127,490 | ||||||
| Basic and diluted net income per limited partner unit | $ | 1.54 | $ | 1.17 | $ | 1.95 | ||||||
| Weighted average number of units outstanding | 81,917 | 67,702 | 64,891 | |||||||||
The accompanying notes are an integral part of these financial statements.
55
NATURAL RESOURCE PARTNERS L.P.
| Holders | ||||||||||||||||||||||||||||
| of Incentive | Non- | Accumulated | ||||||||||||||||||||||||||
| General | Distribution | Controlling | Other | |||||||||||||||||||||||||
| Common Units | Partner | Rights | Interest | Comprehensive | ||||||||||||||||||||||||
| Units | Amounts | Amounts | Amounts | Amounts | Income (Loss) | Total | ||||||||||||||||||||||
| (In thousands, except unit data) | ||||||||||||||||||||||||||||
| Balance at December 31, 2007 | 64,891,136 | $ | 722,931 | $ | 14,405 | $ | 7,954 | $ | — | $ | (699 | ) | $ | 744,591 | ||||||||||||||
| Distributions to unitholders | — | (131,080 | ) | (3,428 | ) | (36,799 | ) | — | — | (171,307 | ) | |||||||||||||||||
| Net income for the year ended | ||||||||||||||||||||||||||||
| December 31, 2008 | — | 127,490 | 2,602 | 39,914 | — | — | 170,006 | |||||||||||||||||||||
| Loss on interest hedge | — | — | — | — | — | 51 | 51 | |||||||||||||||||||||
| Comprehensive income | — | — | — | — | — | 51 | 170,057 | |||||||||||||||||||||
| Balance at December 31, 2008 | 64,891,136 | $ | 719,341 | $ | 13,579 | $ | 11,069 | $ | — | $ | (648 | ) | $ | 743,341 | ||||||||||||||
| Distributions to unitholders | — | (144,766 | ) | (3,762 | ) | (39,607 | ) | — | — | (188,135 | ) | |||||||||||||||||
| Issuance of units for acquisitions, net | 4,560,000 | 93,908 | 1,981 | — | — | — | 95,889 | |||||||||||||||||||||
| Net income for the year ended | ||||||||||||||||||||||||||||
| December 31, 2009 | — | 78,954 | 1,611 | 33,515 | — | — | 114,080 | |||||||||||||||||||||
| Loss on interest hedge | — | — | — | — | — | 51 | 51 | |||||||||||||||||||||
| Comprehensive income | — | — | — | — | — | 51 | 114,131 | |||||||||||||||||||||
| Balance at December 31, 2009 | 69,451,136 | $ | 747,437 | $ | 13,409 | $ | 4,977 | $ | — | $ | (597 | ) | $ | 765,226 | ||||||||||||||
| Distributions to unitholders | — | (174,709 | ) | (4,197 | ) | (30,943 | ) | — | — | (209,849 | ) | |||||||||||||||||
| Issuance of units, net | 36,576,700 | 110,217 | — | — | — | — | 110,217 | |||||||||||||||||||||
| Capital contribution | — | — | 2,350 | — | — | — | 2,350 | |||||||||||||||||||||
| Fees associated with elimination of IDRs | — | (2,341 | ) | — | — | — | — | (2,341 | ) | |||||||||||||||||||
| Non-controlling interest | — | — | — | — | 5,065 | — | 5,065 | |||||||||||||||||||||
| Net income for the year ended | ||||||||||||||||||||||||||||
| December 31, 2010 | — | 125,925 | 2,570 | 25,966 | — | — | 154,461 | |||||||||||||||||||||
| Loss on interest hedge | — | — | — | — | — | 51 | 51 | |||||||||||||||||||||
| Comprehensive income | — | — | — | — | — | 51 | 154,512 | |||||||||||||||||||||
| Balance at December 31, 2010 | 106,027,836 | $ | 806,529 | $ | 14,132 | $ | — | $ | 5,065 | $ | (546 | ) | $ | 825,180 | ||||||||||||||
The accompanying notes are an integral part of these financial statements.
56
NATURAL RESOURCE PARTNERS L.P.
| For the Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Cash flows from operating activities: | ||||||||||||
| Net income | $ | 154,461 | $ | 114,080 | $ | 170,006 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
| Depreciation, depletion and amortization | 56,978 | 60,012 | 64,254 | |||||||||
| Non-cash interest charge | 540 | 1,463 | 278 | |||||||||
| Gain(loss) on sale of assets | — | — | 33 | |||||||||
| Change in operating assets and liabilities: | ||||||||||||
| Accounts receivable | (2,627 | ) | 581 | (4,586 | ) | |||||||
| Other assets | (27 | ) | (67 | ) | 178 | |||||||
| Accounts payable and accrued liabilities | 468 | (133 | ) | (1,484 | ) | |||||||
| Accrued interest | (489 | ) | 3,850 | 143 | ||||||||
| Deferred revenue | 42,491 | 26,264 | 4,468 | |||||||||
| Accrued incentive plan expenses | 6,137 | 4,577 | (3,041 | ) | ||||||||
| Property, franchise and other taxes payable | 762 | 42 | (293 | ) | ||||||||
| Net cash provided by operating activities | 258,694 | 210,669 | 229,956 | |||||||||
| Cash flows from investing activities: | ||||||||||||
| Acquisition of land, coal, other mineral rights and related intangibles | (166,382 | ) | (118,754 | ) | (5,500 | ) | ||||||
| Acquisition or construction of plant and equipment | (5,994 | ) | (1,157 | ) | (10,568 | ) | ||||||
| Proceeds from sale of assets | 1,580 | — | — | |||||||||
| Change in restricted accounts | — | — | 6,240 | |||||||||
| Net cash used in investing activities | (170,796 | ) | (119,911 | ) | (9,828 | ) | ||||||
| Cash flows from financing activities: | ||||||||||||
| Proceeds from loans | 140,000 | 331,000 | — | |||||||||
| Proceeds from issuance of units | 110,436 | — | — | |||||||||
| Deferred financing costs | — | (661 | ) | — | ||||||||
| Repayments of loans | (106,234 | ) | (168,235 | ) | (17,234 | ) | ||||||
| Retirement of purchase obligation related to reserves and infrastructure | (9,169 | ) | (72,000 | ) | — | |||||||
| Costs associated with unit issuance | (219 | ) | (21 | ) | — | |||||||
| Fees associated with elimination of IDRs | (2,341 | ) | — | — | ||||||||
| Distributions to partners | (209,849 | ) | (188,135 | ) | (171,307 | ) | ||||||
| Contributions by general partner | 2,350 | — | — | |||||||||
| Net cash used in financing activities | (75,026 | ) | (98,052 | ) | (188,541 | ) | ||||||
| Net increase (decrease) in cash and cash equivalents | 12,872 | (7,294 | ) | 31,587 | ||||||||
| Cash and cash equivalents at beginning of period | 82,634 | 89,928 | 58,341 | |||||||||
| Cash and cash equivalents at end of period | $ | 95,506 | $ | 82,634 | $ | 89,928 | ||||||
| Supplemental cash flow information: | ||||||||||||
| Cash paid during the period for interest | $ | 41,565 | $ | 34,710 | $ | 27,735 | ||||||
| Non-cash investing activities: | ||||||||||||
| Equity issued for acquisitions | $ | — | $ | 95,910 | $ | — | ||||||
| Assets contributed by general partner for acquisitions | — | 1,981 | — | |||||||||
| Liability assumed from acquisitions | 1,593 | 1,170 | — | |||||||||
| Non-controlling interest | (5,065 | ) | — | — | ||||||||
| Non-cash financing activities: | ||||||||||||
| Purchase obligation related to reserve and infrastructure acquisitions | 6,200 | 74,022 | — | |||||||||
The accompanying notes are an integral part of these financial statements.
57
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. | Basis of Presentation and Organization |
Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning and managing mineral properties in the United States. The Partnership owns coal propertiesreserves in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States.States, as well as lignite reserves in the Gulf Coast region. As of December 31, 2009,2010, the Partnership owned or controlled approximately 2.12.3 billion tons of proven and probable coal reserves (unaudited)., and also owned approximately 228 million tons of aggregate reserves (unaudited) in a number of states across the country. The Partnership does not operate any mines, but leases coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine coal reserves in exchange for royalty payments. Lessees are generally required to make royalty payments based on the higher of a percentage of the gross sales price or a fixed price per ton, of coal sold, in addition to a minimum payment.
In addition, the Partnership owns coal transportation and preparation equipment, aggregate reserves, other coal related rights and oil and gas properties on which it earns revenue.
The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through a wholly owned operating company, NRP (Operating) LLC. NRP (GP) LP, the general partner of the Partnership, has sole responsibility for conducting its business and for managing its operations. Because its 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 its behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson is entitled to nominate all nine of the directors, five of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC. In connection with the Cline acquisition, Mr. Robertson delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, LLC, an affiliate of the Cline Group.
| 2. | Summary of Significant Accounting Policies |
Principles of Consolidation
The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries.subsidiaries as well as BRP LLC, a venture with International Paper Company controlled by the Partnership. Intercompany transactions and balances have been eliminated.
Reclassification
Certain reclassifications have been made to the prior year’s financial statements. Immaterial amounts relating to the AzConAgg and Gatling Ohio acquisitions have been reclassified between various assets based upon more information received by the Partnership with respect to those assets.
Business Combinations
For purchase acquisitions accounted for as a business combination, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. For additional discussion concerning the Partnership’s valuation of intangible assets, see Note 7, “Intangible Assets.”
58
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fair Value Measurements
The Partnership accounts for fair value measurements, including disclosures, using Financial Accounting Standard Board’s (FASB) fair value standard. For additional discussion concerning the Partnership’s fair value measurement, see Note 9, “Fair Value Measurement”Measurements”.
Use of Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
55
Cash Equivalents and Restricted Cash
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents. Restricted cash includes deposits to secure performance under contracts acquired as part of the Cline acquisition. Earnings on the restricted cash are available to the Partnership. Performance under the Cline contracts was completed in November 2008 and the funds were released from escrow at that time.
Accounts Receivable
Accounts receivable are recorded on the basis of tons of minerals sold by the Partnership’s lessees in the ordinary course of business, and do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying consolidated balance sheets. The Partnership evaluates the collectibilitycollectability of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its lessees’ accounts and when it becomes aware of a specific customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. Accounts are charged off when collection efforts are complete and future recovery is doubtful. If circumstances related to specific lessees change, the Partnership’s estimates of the recoverability of receivables could be further adjusted.
Land, Coal and Mineral Rights
Land, coal and other mineral rights owned and leased are recorded at cost. Coal and other mineral rights are depleted on aunit-of-production basis by lease, based upon coalminerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein, or over the amortization period of the contractual rights.
Plant and Equipment
Plant and equipment consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at cost and are being depreciated on a straight-line basis over their useful lives, which range from three to twenty years.
Intangible Assets
The Partnership’s intangible assets consist of above marketabove-market contracts. Intangible assets are identified related to contracts acquired when compared to the estimate of current market rates for similar contracts. The
59
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
estimated fair value of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on aunit-of-production basis. In April 2010, the Partnership was notified by a lessee that its production would be temporarily idled but that the lessee would continue its development work in other areas of the mine. As a result of these circumstances, the Partnership refined its accounting policy to reflect a minimum amortization to be applied in each period for temporarily idled assets. For the year ended December 31, 2010, the Partnership recorded amortization expense of $4.8 million, or approximately $0.06 per unit, that relates to the minimum amortization.
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. During 2009, included in depletion is a onetime charge of $8.2 million related to a terminated lease from a mine closure.
Concentration of Credit Risk
Substantially all of the Partnership’s accounts receivable result from amounts due from third-party companies in the coal industry, with approximately 65%61% of our total revenues being attributable to coal royalty revenues from Appalachia. This concentration of customers may impact the Partnership’s overall credit risk,
56
either positively or negatively, in that these entities may be affected by changes in economic or other conditions. Receivables are generally not collateralized.
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s revolving credit facility and senior notes. These costs are amortized over the term of the debt.
Revenues
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.sell.
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 the Partnership 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, the Partnership receives 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 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
60
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
Property Taxes
The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statementstatements of income as property taxes.
Income Taxes
No provision for income taxes related to the operations of the Partnership has been included in the accompanying financial statements because, as a partnership, it is not subject to federal or material state income taxes and the tax effect of its activities accrues to the unitholders. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under its partnership agreement. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.
Share-Based Payment
The Partnership accounts for awards under its Long-Term Incentive Plan under FASB’s stock compensation authoritative guidance. This authoritative guidance provides that grants must be accounted for using the fair value method, which requires the Partnership 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
57
value. In addition, this authoritative guidance 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.
New Accounting Standards
In December 2010, the FASB amended how a public entity that enters into a material business combination present comparative financial statements. The amendment specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This amendment also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This amendment is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The Partnership will adopt this amendment on January 1, 2011 and, therefore, disclosures related to future material acquisitions accounted for as business combinations that are completed by the Partnership may be impacted by this amendment.
In December 2010, the FASB modified Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors that would indicate an impairment may exist. The qualitative factors are consistent with the existing guidance, which requires that goodwill of a reporting unit be tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the
61
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
fair value of a reporting unit below its carrying amount. This amendment is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2010. The Partnership does not expect this adoption to have a material impact on the financial statements. However, if future business combinations result in goodwill this guidance may become relevant.
In February 2010, the FASB amended the subsequent events standard, removing the requirement for an SEC filer to disclose the date it issued and revised financial statements. The FASB added that revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. GAAP. The Partnership adopted this amendment for the quarter ended March 31, 2010. The adoption did not have a material impact on the Partnership’s disclosures.
In January 2010, the FASB amended fair value disclosure requirements. This amendment requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, seetransfers. See Note 9. “Fair Value Measurements” for the definition of Level 1 and Level 2 measurements. The amendment also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs. This amendment is effective for fiscal years beginning after December 15, 2010 and interim periods within those fiscal years. The Partnership does not expect this amendment to have an impact on the Partnership’s financial position, results of operations or cash flows.
58
Other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.
| 3. | Acquisitions |
BRP LLC. In June 2010, the Partnership and International Paper Company (“IPC”) formed BRP to own and manage mineral assets previously owned by IPC. Some of these assets are currently subject to leases, and certain other assets are available for future development by the venture. In exchange for a $42.5 million contribution, NRP became the controlling member with the right to designate two of the three managers of BRP. NRP has a 51% income interest plus a preferential cumulative annual distribution prior to profit sharing. In exchange for the contribution of the producing properties and the properties not currently producing, IPC received $42.5 million in cash, a minority voting interest and a 49% income interest after the preferential cumulative annual distribution. The amount of the preference is fixed throughout the life of the venture but can be reduced by a portion of the proceeds received from sales of producing properties included in the initial acquisition. Identified tangible assets included in the transaction are oil and gas, coal, and aggregate reserves, as well the rights to other unidentified minerals which may include coal bed methane, geothermal, CO2 sequestration, water rights, precious metals, industrial minerals and base metals. Certain properties, including oil and gas, coal and aggregates, as well as land leased for cell towers, are currently under lease and generating revenues.
The transaction was accounted for as a business combination and, at December 31, 2010, the assets and liabilities of the venture are included in the consolidated balance sheet. The allocation of the purchase price
62
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
was based on preliminary results of independent third party valuations. The initial estimates and assumptions used are subject to change upon the receipt of additional information required to finalize the valuations, which may result in changes to the coal and other mineral rights, intangible assets and non-controlling interests. The final valuation of the assets is expected to be completed as soon as possible, but no later than one year from the acquisition date. The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed for the BRP transaction (in thousands):
| Coal and other mineral rights | $ | 45,759 | ||
| Intangible assets | 1,806 | |||
| Capital contribution | 42,500 | |||
| Non-controlling interests | 5,065 |
Approximately $38.3 million of the total $47.6 million asset fair value, as well as the value of the $5.1 million non-controlling interest, were estimated using an expected cash flows approach. The remaining assets fair value was determined using a market approach. The capital contribution was funded through a $30 million draw on the Partnership’s credit facility and the remainder was funded with available cash. See Note 9, “Fair Value Measurements”. The identification of all tangible and intangible assets acquired as well as the valuation process required for the allocation of the purchase price to those assets is not complete.
Operations of the venture are included from June 1, 2010, the effective date of acquisition. Total net income from startup through December 31, 2010 was $2.3 million. The venture operating agreement provides that net income of the venture only be allocated to the non-controlling interests after the preferential cumulative annual distribution. As earnings for the period ended December 31, 2010 were less than the preference amount, no earnings were allocated to the non-controlling interest.
Transaction expenses related to the acquisition were $2.5 million and are included in general and administrative expenses in the accompanying Consolidated Statements of Income.
Rockmart Slate. In June 2010, the Partnership acquired approximately 100 acres of mineral and surface rights related to slate reserves in Rockmart, Georgia from a local operator for a purchase price of $6.7 million.
Sierra Silica. In April 2010, the Partnership acquired the rights to silica reserves on approximately 1,000 acres of property in Northern California for $17.0 million.
North American Limestone. In April 2010, the Partnership signed an agreement to build and own a fine grind processing facility for high calcium carbonate limestone located in Putnam County, Indiana. The Partnership will lease the facility to a local operator. The total cost for the facility is not to exceed $6.5 million. As of December 31, 2010 the Partnership had incurred approximately $5.9 million of costs associated with the construction of the facility.
Northgate-Thayer. In March 2010, the Partnership acquired approximately 100 acres of mineral and surface rights related to dolomite limestone reserves in White County, Indiana from a local operator for a purchase price of $7.5 million.
Massey-Override. In March 2010, the Partnership acquired from Massey Energy subsidiaries overriding royalty interests in coal reserves located in southern West Virginia and eastern Kentucky. Total consideration for this purchase was $3.0 million.
AzConAgg. In December 2009, the Partnership acquired approximately 230 acres of mineral and surface rights related to sand and gravel reserves in southern Arizona from a local operator for $3.75 million.
Colt. In September 2009, the Partnership signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the
63
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Cline Group, through eightseveral separate transactions for a total purchase price of $255 million. Upon closingAs of the first transaction,December 31, 2010, the Partnership paid $10.0 million, funded through the Partnership’s credit facility, andhad acquired approximately 3.350.2 million tons of reserves associated with the initial production from the mine.mine for approximately $105 million. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.mine.
Blue Star. In July 2009, the Partnership acquired approximately 121 acres of limestone reserves in Wise County, Texas from Blue Star Materials, LLC for a purchase price of $24 million. As of December 31, 2009, the Partnership had funded $21.0 million of the acquisition with cash and borrowings under the Partnership’s credit facility.
Gatling Ohio. In May 2009, the Partnership completed the purchase of the membership interests in two companies from Adena Minerals, LLC, an affiliate of the Cline Group. The companies own 51.5 million tons of coal reserves and infrastructure assets at Cline’s Yellowbush Mine located on the Ohio River in Meigs County, Ohio. The Partnership issued 4,560,000 common units to Adena Minerals in connection with this
59
acquisition. In addition, the general partner of Natural Resource Partners granted Adena Minerals an additional nine percent interest in the general partner as well as additional incentive distribution rights.partner.
Macoupin. In January 2009, the Partnership acquired approximately 82 million tons of 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.
| 4. | Allowance for Doubtful Accounts |
Activity in the allowance for doubtful accounts for the years ended December 31, 2010, 2009 2008 and 20072008 was as follows:
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||||||||
| (In thousands) | (In thousands) | |||||||||||||||||||||||
| Balance, January 1 | $ | 366 | $ | 1,272 | $ | 906 | $ | 372 | $ | 366 | $ | 1,272 | ||||||||||||
| Provision charged to operations: | ||||||||||||||||||||||||
| Additions to the reserve | 37 | 366 | 871 | 309 | 37 | 366 | ||||||||||||||||||
| Collections of previously reserved accounts | (31 | ) | (1,037 | ) | (505 | ) | — | (31 | ) | (1,037 | ) | |||||||||||||
| Total charged (credited) to operations | 6 | (671 | ) | 366 | 309 | 6 | (671 | ) | ||||||||||||||||
| Non-recoverable balances written off | — | (235 | ) | — | — | — | (235 | ) | ||||||||||||||||
| Balance, December 31 | $ | 372 | $ | 366 | $ | 1,272 | $ | 681 | $ | 372 | $ | 366 | ||||||||||||
| 5. | Plant and Equipment |
The Partnership’s plant and equipment consist of the following:
| December 31, | December 31, | December 31, | December 31, | |||||||||||||
| 2009 | 2008 | 2010 | 2009 | |||||||||||||
| (In thousands) | (In thousands) | |||||||||||||||
| Plant construction in process | $ | — | $ | 8,524 | $ | 6,279 | $ | — | ||||||||
| Plant and equipment at cost | 81,782 | 68,197 | 81,906 | 81,866 | ||||||||||||
| Less accumulated depreciation | (17,515 | ) | (9,517 | ) | (25,837 | ) | (17,515 | ) | ||||||||
| Net book value | $ | 64,267 | $ | 67,204 | $ | 62,348 | $ | 64,351 | ||||||||
6064
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| For the Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
| Total depreciation expense on plant and equipment | $ | 7,998 | $ | 4,965 | $ | 3,904 | ||||||
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Total depreciation expense on plant and equipment | $ | 8,322 | $ | 7,998 | $ | 4,965 | ||||||
| 6. | Coal and Other Mineral Rights |
The Partnership’s coal and other mineral rights consist of the following:
| December 31, | December 31, | December 31, | December 31, | |||||||||||||
| 2009 | 2008 | 2010 | 2009 | |||||||||||||
| (In thousands) | (In thousands) | |||||||||||||||
| Coal and other mineral rights | $ | 1,460,462 | $ | 1,253,314 | $ | 1,629,286 | $ | 1,460,984 | ||||||||
| Less accumulated depletion and amortization | (309,149 | ) | (273,622 | ) | (347,650 | ) | (309,149 | ) | ||||||||
| Net book value | $ | 1,151,313 | $ | 979,692 | $ | 1,281,636 | $ | 1,151,835 | ||||||||
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
| Total depletion and amortization expense on coal and other mineral interests | $ | 48,591 | $ | 55,896 | $ | 45,519 | ||||||
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Total depletion and amortization expense on coal and other mineral interests | $ | 38,501 | $ | 48,591 | $ | 55,896 | ||||||
Included in depletion in 2009 is a onetime charge of $8.2 million related to a terminated lease from a mine closure.
| 7. | Intangible Assets |
In 2010, the Partnership identified $7.5 million of contract intangibles relating to the Sierra Silica acquisition and the IPC venture. In 2009, the Partnership identified $65.8 million of above market contractscontract intangibles relating to the Gatling Ohio and Macoupin acquisitions .acquisitions. Amounts recorded as intangible assets along with the balances and accumulated amortization at December 31, 20092010 and 20082009 are reflected in the table below:
| December 31, | December 31, | December 31, | December 31, | |||||||||||||
| 2009 | 2008 | 2010 | 2009 | |||||||||||||
| (In thousands) | (In thousands) | |||||||||||||||
| Above market contracts | $ | 173,312 | $ | 107,557 | ||||||||||||
| Contract intangibles | $ | 180,233 | $ | 172,706 | ||||||||||||
| Less accumulated amortization | (8,152 | ) | (4,729 | ) | (18,302 | ) | (8,152 | ) | ||||||||
| Net book value | $ | 165,160 | $ | 102,828 | $ | 161,931 | $ | 164,554 | ||||||||
| For the Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In thousands) | ||||||||||||
| Total amortization expense on intangible assets | $ | 3,423 | $ | 3,394 | $ | 1,335 | ||||||
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Total amortization expense on intangible assets | $ | 10,150 | $ | 3,423 | $ | 3,394 | ||||||
65
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
to be applied in each period for temporarily idled assets. For the year ended December 31, 2010, the Partnership recorded amortization expense is based uponof $4.8 million, or approximately $0.06 per unit, that relates to the production and sales of coal from acquired reserves and the number of tons of coal transported using the transportation infrastructure. minimum amortization.
The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods.
61
| Estimated amortization expense (In thousands) | ||||||||
| For year ended December 31, 2010 | $ | 4,664 | ||||||
| For year ended December 31, 2011 | 5,330 | $ | 15,096 | |||||
| For year ended December 31, 2012 | 5,098 | 11,189 | ||||||
| For year ended December 31, 2013 | 5,098 | 10,535 | ||||||
| For year ended December 31, 2014 | 5,098 | 10,535 | ||||||
| For year ended December 31, 2015 | 10,535 | |||||||
| 8. | Long-Term Debt |
Long-term debt consists of the following:
| December 31, | December 31, | |||||||
| 2009 | 2008 | |||||||
| (In thousands) | ||||||||
| $300 million floating rate revolving credit facility, due March 2012 | $ | 28,000 | $ | 48,000 | ||||
| 5.55% senior notes, with semi-annual interest payments in June and December, maturing June 2013 | 35,000 | 35,000 | ||||||
| 4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018 | 43,700 | 49,750 | ||||||
| 8.38% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2013, maturing in March 2019 | 150,000 | — | ||||||
| 5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020 | 84,615 | 92,308 | ||||||
| 5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 | 2,307 | 2,499 | ||||||
| 5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023 | 40,200 | 43,500 | ||||||
| 5.82% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2010, maturing in March 2024 | 225,000 | 225,000 | ||||||
| 8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 | 50,000 | — | ||||||
| Total debt | 658,822 | 496,057 | ||||||
| Less — current portion of long term debt | (32,235 | ) | (17,235 | ) | ||||
| Long-term debt | $ | 626,587 | $ | 478,822 | ||||
| 2010 | $ | 32,235 | ||
| 2011 | 31,518 | |||
| 2012 | 58,801 | |||
| 2013 | 87,230 | |||
| 2014 | 56,175 | |||
| Thereafter | 392,863 | |||
| $ | 658,822 | |||
| December 31, | December 31, | |||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
| $300 million floating rate revolving credit facility, due March 2012 | $ | 94,000 | $ | 28,000 | ||||
| 5.55% senior notes, with semi-annual interest payments in June and December, maturing June 2013 | 35,000 | 35,000 | ||||||
| 4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018 | 37,650 | 43,700 | ||||||
| 8.38% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2013, maturing in March 2019 | 150,000 | 150,000 | ||||||
| 5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020 | 76,923 | 84,615 | ||||||
| 5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 | 2,115 | 2,307 | ||||||
| 5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023 | 36,900 | 40,200 | ||||||
| 5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024 | 210,000 | 225,000 | ||||||
| 8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 | 50,000 | 50,000 | ||||||
| Total debt | 692,588 | 658,822 | ||||||
| Less — current portion of long term debt | (31,518 | ) | (32,235 | ) | ||||
| Long-term debt | $ | 661,070 | $ | 626,587 | ||||
62
66
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Principal payments due in:
| Senior Notes | Credit Facility | Total | ||||||||||
| (In thousands) | ||||||||||||
| 2011 | $ | 31,518 | $ | — | $ | 31,518 | ||||||
| 2012 | 30,801 | 94,000 | 124,801 | |||||||||
| 2013 | 87,230 | — | 87,230 | |||||||||
| 2014 | 56,175 | — | 56,175 | |||||||||
| 2015 | 56,175 | — | 56,175 | |||||||||
| Thereafter | 336,689 | — | 336,689 | |||||||||
| $ | 598,588 | $ | 94,000 | $ | 692,588 | |||||||
The senior note purchase agreement contains covenants requiring our operating subsidiary to:
| • | Maintain a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters; | |
| • | not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and | |
| • | maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0. |
The Partnership made principal payments of $32.2 million and $17.2 million on its senior notes for the years ended December 31, 2010 and 2009, and 2008.respectively.
The Partnership has a $300 million revolving credit facility, and at December 31, 2009, $2722010, $206 million was available under the facility. The Partnership incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.10% to 0.30% per annum. Under an accordion feature in the credit facility, the Partnership may request its lenders to increase their aggregate commitment to a maximum of $450 million on the same terms. However, the Partnership cannot be certain that its lenders will elect to participate in the accordion feature. To the extent the lenders decline to participate, the Partnership may elect to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be available on existing or comparable terms.
The Partnership had $28.0$94.0 million and $48.0$28.0 million outstanding on its revolving credit facility at December 31, 20092010 and 2008,2009, respectively. The weighted average interest rate at December 31, 2010 and 2009 was 1.42% and 2008 was 2.07% and 5.14%, respectively. Interest capitalized as part of the construction cost of Plant and Equipment was $0.2 million in 2008.
The revolving credit facility contains covenants requiring the Partnership to maintain:
| • | a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and | |
| • | a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters. |
67
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Partnership was in compliance with all terms under its long-term debt as of December 31, 2009.2010.
| 9. | Fair Value Measurements |
The Partnership discloses certain assets and liabilities using fair value as defined by FASB’s fair value authoritative guidance.
FASB’s guidance describes three levels of inputs that may be used to measure fair value:
| • | Level 1 — Quoted prices in active markets for identical assets or liabilities. | |
| • | Level 2 — Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. | |
| • | Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments |
63
| whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation. |
The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of the Partnership’s financial instruments included in accounts receivable and accounts payable approximates their fair value due to their short-term nature. The Partnership’s cash and cash equivalents include money market accounts and are considered a Level 1 measurement. The fair market value of the Partnership’s long-term debt was estimated to be $627.5$596.1 million and $385.5$627.5 million at December 31, 20092010 and 2008,2009, respectively, for the senior notes. The carrying value of the Partnership’s long-term debtsenior notes was $658.8$598.6 million and $496.1$630.8 million at December 31, 2010 and 2009, and 2008, respectively, for the senior notes.respectively. The fair value is estimated by management using comparable term risk-free treasury issues with a market rate component determined by current financial instruments with similar characteristics which is a Level 3 measurement. Since the Partnership’s credit facility is variable rate debt, its fair value approximates its carrying amount.
| 10. |
In connection with an acquisition, the holders of the IDRs elected to cap the distribution at Tier III for the quarters ending September 30, 2009 and December 31, 2009. The increase in basic and diluted net income per limited partner unit due to the forgone distributions for the year ended December 31, 2009 was $0.21 per unit.
On September 20, 2010, the Partnership eliminated all of the incentive distribution rights (IDRs) held by its general partner and affiliates of the general partner. As consideration for the elimination of the IDRs, the Partnership issued 32 million common units to the holders of the IDRs. As of the date of this report, there are 106,027,836 common units outstanding and the general partner has retained its 2% interest in the Partnership.
| 11. | Related Party Transactions |
Reimbursements to Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information
68
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates.
64
The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $6.8are as follows:
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Reimbursement for services | $ | 7,358 | $ | 6,822 | $ | 5,557 | ||||||
The Partnership leases substantially all of two floors of an office building in Huntington, West Virginia from Western Pocahontas Properties and pays $0.5 million $5.6 million and $5.0 million for the years endedin lease payments each year through December 31, 2009, 2008 and 2007, respectively. At December 31, 2009 and 2008, the Partnership also had accounts payable to affiliates of $0.2 million and $0.4 million, respectively.2018.
Transactions with Cline Affiliates
Various companies controlled by Chris Cline lease coal reserves from the Partnership, and the Partnership provides coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in the Partnership’s general partner, and in the incentive distribution rights of the Partnership, as well as 13,510,07221,017,441 common units. At December 31, 2009 and 2008,2010, the Partnership had accounts receivable totaling $4.0 million and $1.6$6.5 million from Cline affiliates. Revenues from the Cline affiliates respectively. For the years endedare as follows:
| For the Year Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Coal royalty revenues | $ | 32,407 | $ | 23,325 | $ | 19,255 | ||||||
| Coal processing fees | 1,337 | 193 | — | |||||||||
| Transportation fees | 14,324 | 11,495 | 6,895 | |||||||||
| Minimums recognized as revenue | 12,400 | — | — | |||||||||
| Override revenue | 1,904 | 2,356 | 1,788 | |||||||||
| $ | 62,372 | $ | 37,369 | $ | 27,938 | |||||||
As of December 31, 2009, 2008 and 2007,2010, the Partnership had total revenue of $37.4received $47.0 million $27.9 million and $7.5 million, respectively, from these companies. In addition, the Partnership has also received $16.2 million in advance minimum royalty payments that have not been recouped.recouped by Cline affiliates, of which $22.8 million was received in the current year.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in NRP’s conflicts policy.
A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s5-person board of directors. The Partnership currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. The Partnership owns and leases the plants to Taggart Global, which designs, builds and operates the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. To date, the Partnership has
69
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
acquired four facilities under this agreement with Taggart with a total cost of $46.6 million. For the years ended December 31, 2009, 2008 and 2007, the Partnership received total revenue of $3.9 million, $5.0 million and $2.7 million, respectively,Revenues from Taggart. Taggart are as follows:
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Coal processing revenue | $ | 5,874 | $ | 3,872 | $ | 4,971 | ||||||
At December 31, 2009 and 2008,2010, the Partnership had accounts receivable totaling $0.2 million and $0.4$1.3 million from Taggart, respectively.Taggart.
A fund controlled by Quintana Capital owns Kopper-Glo, a small coal mining company that is one of the Partnership’s lessees with operations in Tennessee. For the years endedRevenues from Kopper-Glo are as follows:
| For the Years Ended | ||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
| Coal royalty revenues | $ | 1,545 | $ | 1,560 | $ | 1,445 | ||||||
At December 31, 2009, 2008 and 2007,2010, the Partnership had total revenue of $1.6 million, $1.4 million and $0.1 million, respectively, from Kopper-Glo, and at December 31, 2009 and 2008, the Partnershipalso had accounts receivable totaling $0.1 million and $0.2 million from Kopper-Glo, respectively.
| 12. | Commitments and Contingencies |
Legal
The Partnership is 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, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.
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Environmental Compliance
The operations conducted on the Partnership’s properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties as of December 31, 2009.2010. The Partnership is not associated with any environmental contamination that may require remediation costs.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| 13. | Major Lessees |
The Partnership has the following lessees that generated in excess of ten percent of total revenues in any one of the years ended December 31, 2010, 2009 2008 and 2007.2008. Revenues from that lesseethese lessees are as follows:
| For the Years Ended December 31, | For the Years Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||||||||||
| Revenues | Percent | Revenues | Percent | Revenues | Percent | Revenues | Percent | Revenues | Percent | Revenues | Percent | |||||||||||||||||||||||||||||||||||||
| (Dollars in thousands) | (Dollars in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| The Cline Group | $ | 62,372 | 20.7 | % | $ | 37,369 | 14.6 | % | $ | 27,938 | 9.6 | % | ||||||||||||||||||||||||||||||||||||
| Massey Energy Company | $ | 42,910 | 14.2 | % | $ | 19,390 | 7.6 | % | $ | 22,015 | 7.6 | % | ||||||||||||||||||||||||||||||||||||
| Alpha Natural Resources | $ | 28,941 | 11.3 | % | $ | 37,400 | 12.8 | % | $ | 26,481 | 12.3 | % | $ | 36,175 | 12.0 | % | $ | 28,941 | 11.3 | % | $ | 37,400 | 12.8 | % | ||||||||||||||||||||||||
| The Cline Group | $ | 37,368 | 14.6 | % | $ | 27,938 | 9.6 | % | $ | 7,525 | 3.5 | % | ||||||||||||||||||||||||||||||||||||
In 2010, the Partnership derived over 20% of its revenue from the Cline Group, 14% from Massey Energy Company and 12% from Alpha Natural Resources. Cline’s Williamson mine alone was responsible for approximately 10% of our revenues in 2010. As a result, the Partnership has a significant concentration of revenues with those lessees, although in most cases, with the exception of Williamson, the exposure is spread out over a number of different mining operations and leases.
| 14. | Incentive Plans |
GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.
Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.
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A summary of activity in the outstanding grants for the year ended December 31, 20092010 are as follows:
| Outstanding grants at the beginning of the period | ||||
| Grants during the period | ||||
| Grants vested and paid during the period | ( | ) | ||
| Forfeitures during the period | ) | |||
| Outstanding grants at the end of the period | ||||
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability fluctuates with the market value of the Partnership units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and historical volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.65%0.21% to 1.57%1.01% and 44.17%30.36% to 57.65%50.22%, respectively at December 31, 2009.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2010. The Partnership’s historical dividend rate of 6.55%6.76% was used in the calculation at December 31, 2009.2010. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $10.6$9.0 million and $6.1$10.6 million for the years ended December 31, 20092010 and 2007,2009, respectively. During 2008, the Partnership reversed accruals of approximately $0.3 million due to the decrease in unit price from December 31, 2007 to December 31, 2008. In connection with the Long-Term Incentive Plans, cash payments of $3.2 million, $2.9 million $3.2 million and $5.8$3.2 million were paid during each of the years ended December 31, 2010, 2009, 2008, and 2007,2008, respectively. The grant date fair value was $29.42, $31.01 $36.22 and $34.64$36.22 per unit for awards in 2010, 2009 2008 and 2007,2008, respectively and the unaccrued cost associated with the unvested outstanding grants at December 31, 20092010 was $8.2$11.9 million.
In connection with the phantom unit awards granted in February 2008, 2009 and 2009,2010, the CNG Committeecompensation committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units.units during the vesting period. The DERs have a four-year vestingvest over the same period as the related phantom units, and the Partnership accrues the cost of the distributions over that period. The expense associated with the DERs is included in the LTIP accrual for each year.
| 15. | Subsequent Events (Unaudited) |
The following represents material events that have occurred subsequent to December 31, 20092010 through the time of the Partnership’s filing on February 26, 2010, the date the Partnership’sitsForm 10-K was filed with the Securities and Exchange Commission:
Acquisitions
On January 11, 2010,13, 2011, the Partnership closed the second transaction withfourth acquisition of reserves from Colt, LLC, an affiliate of the Cline Group. The Partnership paid $40.0$70.0 million, funded through its credit facility, and acquired approximately 19.541.9 million tons of coal reserves.
On January 15, 2010,February 22, 2011, the Partnership paid the final $3.0 millionacquired approximately 508 acres of the total of $24.0 million for the acquisition ofmineral and surface rights related to limestone reserves from Blue Star Materials, LLC,in Livingston County, Kentucky for a purchase price of $16 million, $11 million of which was funded through its credit facility.at closing.
Distributions
On February 12, 2010,January 19, 2011, the Partnership paiddeclared a quarterly distribution of $0.54 per unit to all holdersbe paid on February 14, 2011 to unitholders of common units.record on February 4, 2011.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| 16. | Supplemental Financial Data (Unaudited) |
Shown below are selected unaudited quarterly data. Amounts are rounded for consistency in presentation with no effect to the results of operations previously reported onForm 10-Q orForm 10-K.
Selected Quarterly Financial Information
(In thousands, except per unit data)
(In thousands, except per unit data)
| First | Second | Third | Fourth | |||||||||||||
| 2010 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
| Total revenues | $ | 63,519 | $ | 79,588 | $ | 80,752 | $ | 77,543 | ||||||||
| Income from operations | $ | 40,912 | $ | 51,953 | $ | 50,344 | $ | 52,852 | ||||||||
| Net income | $ | 30,191 | $ | 41,611 | $ | 40,153 | $ | 42,506 | ||||||||
| Basic and diluted net income per limited partner unit | $ | 0.24 | $ | 0.38 | $ | 0.51 | $ | 0.39 | ||||||||
| Weighted average number of units outstanding: | ||||||||||||||||
| Common | 69,451 | 74,028 | 77,896 | 106,028 | ||||||||||||
| First | Second | Third | Fourth | |||||||||||||
| 2009 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
| Total revenues | $ | 66,733 | $ | 59,487 | $ | 63,962 | $ | 65,902 | ||||||||
| Income from operations | $ | 41,417 | $ | 27,661 | $ | 41,395 | $ | 43,502 | ||||||||
| Net income | $ | 33,420 | $ | 17,082 | $ | 30,651 | $ | 32,927 | ||||||||
| Basic and diluted net income per limited partner unit | $ | 0.33 | $ | 0.07 | $ | 0.36 | $ | 0.39 | ||||||||
| Weighted average number of units outstanding: | ||||||||||||||||
| Common | 64,891 | 66,946 | 69,451 | 69,451 | ||||||||||||
| First | Second | Third | Fourth | |||||||||||||
2008 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
| Total revenues | $ | 64,055 | $ | 75,592 | $ | 76,196 | $ | 75,822 | ||||||||
| Income from operations | $ | 40,768 | $ | 47,105 | $ | 53,882 | $ | 55,252 | ||||||||
| Net income | $ | 33,852 | $ | 40,353 | $ | 47,338 | $ | 48,463 | ||||||||
| Basic and diluted net income per limited partner unit(1) | $ | 0.38 | $ | 0.46 | $ | 0.55 | $ | 0.56 | ||||||||
| Weighted average number of units outstanding: | ||||||||||||||||
| Common | 64,891 | 64,891 | 64,891 | 64,891 | ||||||||||||
Second quarter 2009 net income decreased primarily due to lower revenues and a charge of $8.2 million in depletion expense related to a terminated lease from a mine closure.
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| Item 9. | Changes In and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined inRule 13a-15(e) of the Securities Exchange Act) as of December 31, 2009.2010. This evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective in producing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosures.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange ActRules 13a-15(f) and15d-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 20092010 based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.2010. No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s consolidated financial statements included in thisForm 10-K, has issued a report on the Partnership’s internal control over financial reporting, which is included herein.
Report of Independent Registered Public Accounting Firm
The Partners of Natural Resource Partners L.P.
We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2009,2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Natural Resource Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
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financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
69
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 20092010 and 2008,2009, and the related consolidated statements of income, partners’ capital and cash flows for each of the three years in the period ended December 31, 20092010 of Natural Resource Partners L.P. and our report dated February 26, 201028, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 26, 201028, 2011
| Item 9B. | Other Information |
None.
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PART III
| Item 10. | Directors and Executive Officers of the Managing General Partner and Corporate Governance |
As a master limited partnership we do not employ any of the people responsible for the management of our properties. Instead, we reimburse affiliates of our managing general partner, GP Natural Resource Partners LLC, for their services. The following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC. Each officer and director is elected for their respective office or directorship on an annual basis. Unless otherwise noted below, the individuals served as officers or directors of the partnership since the initial public offering. 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.
Name | Age | Position with the General Partner | ||||
| Corbin J. Robertson, Jr. | Chairman of the Board and Chief Executive Officer | |||||
| Nick Carter | President and Chief Operating Officer | |||||
| Dwight L. Dunlap | Chief Financial Officer and Treasurer | |||||
| Kevin F. Wall | Executive Vice President — Operations | |||||
| Wyatt L. Hogan | Vice President, General Counsel and Secretary | |||||
| Dennis F. Coker | Vice President, Aggregates | |||||
| Kevin J. Craig | Vice President, Business Development | |||||
| Kenneth Hudson | Controller | |||||
| Kathy H. Roberts | Vice President, Investor Relations | |||||
| Robert T. Blakely | Director | |||||
| David M. Carmichael | Director | |||||
| J. Matthew Fifield | Director | |||||
| Robert B. Karn III | Director | |||||
| S. Reed Morian | Director | |||||
| W. W. Scott, Jr. | Director | |||||
| Stephen P. Smith | Director | |||||
| Leo A. Vecellio, Jr. | Director | |||||
Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC since 2002. Mr. Robertson has vast business experience having founded and served as a director and as an officer of multiple companies, both private and public, and has served on the boards of numerous non-profit organizations. He has served as the Chief Executive Officer and Chairman of the Board of the general partners of Western Pocahontas Properties Limited Partnership since 1986, Great Northern Properties Limited Partnership since 1992, Quintana Minerals Corporation since 1978, and as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986. He also serves as a Principal with Quintana Capital Group, Chairman of the Board of the Cullen Trust for Higher Education and on the boards of the American Petroleum Institute, the National Petroleum Council, the Baylor College of Medicine and the World Health and Golf Association. In 2006, Mr. Robertson was inducted into the Texas Business Hall of Fame.
Nick Carterhas served as President and Chief Operating Officer of GP Natural Resource Partners LLC since 2002. He has also served as President of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation since 1990 and as President of the general partner of Great Northern Properties Limited Partnership from 1992 to 1998. Prior to 1990, Mr. Carter held various positions with MAPCO Coal Corporation and was engaged in the private practice of law. He is Chairman of the National Council of Coal Lessors, a past Chair of the West Virginia Chamber of Commerce and a board member of the Kentucky Coal Association, West Virginia Coal Association, Indiana Coal Council, National
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Mining Association, ACCCE, Foundation for the Tri-State Community, Inc., Community Trust Bancorp, Inc., Vigo Coal Company, Inc. and Carbo*Prill, Inc.
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Dwight L. Dunlaphas served as the Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC since 2002. Mr. Dunlap has served as Vice President and Treasurer of Quintana Minerals Corporation and as Chief Financial Officer, Treasurer and Assistant Secretary of the general partner of Western Pocahontas Properties Limited Partnership, Chief Financial Officer and Treasurer of Great Northern Properties Limited Partnership and Chief Financial Officer, Treasurer and Secretary of New Gauley Coal Corporation since 2000. Mr. Dunlap has worked for Quintana Minerals since 1982 and has served as Vice President and Treasurer since 1987. Mr. Dunlap is a Certified Public Accountant with over 30 years of experience in financial management, accounting and reporting including six years of audit experience with an international public accounting firm.
Kevin F. Wallhas served as Executive Vice President — Operations of GP Natural Resource Partners LLC since 2008. Mr. Wall was promoted to Executive Vice President — Operations in December 2008. Prior to then he served as Vice President — Engineering for GP Natural Resource Partners LLC from2002-2008, the general partner of Western Pocahontas Properties Limited Partnership since 1998 and the general partner of Great Northern Properties Limited Partnership since 1992. He has also served as the Vice President — Engineering of New Gauley Coal Corporation since 1998. He has performed duties in the land management, planning, project evaluation, acquisition and engineering areas since 1981. He is a Registered Professional Engineer in West Virginia and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers and of the National Society of Professional Engineers. Mr. Wall also serves on the Board of Directors of Leadership Tri-State as well as the Board of the Virginia Center for Coal and Energy Research and is a past president of the West Virginia Society of Professional Engineers.
Wyatt L. Hoganhas served as Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC since 2003. Mr. Hogan joined NRP in May 2003 from Vinson & Elkins L.L.P., where he practiced corporate and securities law from August 2000 through April 2003. He has also served since 2003 as the Vice President, General Counsel and Secretary of Quintana Minerals Corporation, the Secretary for the general partner of Western Pocahontas Properties Limited Partnership and as General Counsel and Secretary for the general partner of Great Northern Properties Limited Partnership. He is also member of the Board of Directors of Quintana Minerals Corporation. Prior to joining Vinson & Elkins in August 2000, he practiced corporate and securities law at Andrews & Kurth L.L.P. from September 1997 through July 2000.
Dennis F. Cokeris Vice President, Aggregates of GP Natural Resource Partners LLC. Mr. Coker joined NRP in March 2008 from Hanson Building Materials America, where he had been employed since 2002, and most recently served as Director, Corporate Development. Mr. Coker has 14 years of experience in the aggregate industry, with the last nineeleven years focused on business development activity. He formerly served as Chairman of the Young Leaders Council of the National Stone Sand and Gravel Association.
Kevin J. Craigis the Vice President of Business Development for GP Natural Resource Partners LLC. Mr. Craig joined NRP in 2005 from CSX Transportation, where he served as Terminal Manager for the West Virginia Coalfields. He has extensive marketing and finance experience with CSX since 1996. Mr. Craig also serves as a Delegate to the West Virginia House of Delegates having been elected in 2000 and re-elected in 2002, 2004, 2006, 2008 and 2008.2010. Mr. Craig currently serves as Vice Chairman of the Committee on Economic Development. Prior to joining CSX, he served as a Captain in the United States Army.
Kenneth Hudsonhas served as the Controller of GP Natural Resource Partners LLC since 2002. He has served as Controller of the general partner of Western Pocahontas Properties Limited Partnership and of New Gauley Coal Corporation since 1988 and of the general partner of Great Northern Properties Limited Partnership since 1992. He was also Controller of Blackhawk Mining Co., Quintana Coal Co. and other related operations from 1985 to 1988. Prior to that time, Mr. Hudson worked in public accounting.
Kathy H. Robertsis Vice President, Investor Relations of GP Natural Resource Partners LLC. Ms. Roberts joined NRP in July 2002. She was the Principal of IR Consulting Associates from 2001 to July 2002 and from 1980 through 2000 held various financial and investor relations positions with Santa Fe Energy Resources,
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most recently as Vice President — Public Affairs. She is a Certified Public Accountant. Ms. Roberts currently serves on the Board of Directors of the National Association of Publicly Traded Partnerships and has served on the local board of directors of the National Investor Relations Institute and maintained professional
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affiliations with various energy industry organizations. She has also served on the Executive Committee and as a National Vice President of the Institute of Management Accountants.
Robert T. Blakelyjoined the Board of Directors of GP Natural Resource Partners LLC in January 2003. Mr. Blakely has extensive public company experience having served as Executive Vice President and Chief Financial Officer for several companies. He is currently the Chairman and Chief Executive Officer of Professional Racing Equipment, Inc., a leading distributor of racing components to NASCAR and professional road racing teams. From January 2006 until August 2007, he served as Executive Vice President and Chief Financial Officer of Fannie Mae, and from August 2007 to January 2008 as an Executive Vice President at Fannie Mae. From mid-2003 through January 2006, he was Executive Vice President and Chief Financial Officer of MCI, Inc. He previously served as Executive Vice President and Chief Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco, Inc. from 1981 until 1999 as well as a Managing Director at Morgan Stanley. More recently he founded and serves as President of Performance Enhancement Group, a private company that was formed to acquire manufacturers of high performance and racing components designed for automotive and marine-engine applications. He currently serves as a Trustee of the Financial Accounting Federation and is a trustee emeritus of Cornell University. He has served on the Board of Directors and as Chairman of the Audit Committee of Westlake Chemical Corporation since August 2004. In 2009, Mr. Blakely joined the Boards of Directors of Ally Financial (formerly GMAC, Inc.), where he serves as Chairman of the Audit Committee, and Greenhill & Co., where he serves as Chairman of the Nominating and Governance Committee.
David M. Carmichaeljoined the Board of Directors of GP Natural Resource Partners LLC in 2002. While Mr. Carmichael has been a private investor since June 1996, he has formerly served as Chairman and Chief Executive Officer at several public companies and currently serves on the board of directors of two public companies. Between 1994 and 1996, he served as Vice Chairman and Chairman of the Management Committee of KN Energy, Inc., a predecessor to Kinder Morgan, Inc. From 1985 until its merger with KN Energy, Inc. in 1994, Mr. Carmichael served as Chairman, Chief Executive Officer and President of American Oil and Gas Corporation. He formed CARCON Corporation in 1984, where he served as President and Chief Executive Officer until its merger into American Oil and Gas Corporation in 1986. From 1976 to 1984, Mr. Carmichael was Chairman and Chief Executive Officer of WellTech, Inc. He served in various senior management positions with Reading and Bates Corporation between 1965 and 1976. He has served on the Board of Directors of ENSCO International sincefrom 2001 to 2010, Cabot Oil and Gas since 2006, and Tom Brown, Inc. from 1997 until 2004. Mr. Carmichael serves on the Nominating and Governance Committee and the Compensation Committee for Cabot and on the Compensation, Nominating and Governance Committees for ENSCO. He also currently serves as a trustee of the Texas Heart Institute.
J. Matthew Fifieldis a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Fifield brings coal mining and financial experience to NRP’s board of directors. Mr. Fifield joined NRP’s Board of Directors in January 2007. He currently serves as a Managing Director of Foresight Management, LLC, a Cline Group affiliate and is responsible for business development.development and as a Managing Director of Gogebic Taconite, LLC, a development stage iron mining company, a Cline Group affiliate. Since 2005, he has also served as a Managing Director of both Adena Minerals, LLC and Cline Resource & Development Company, both Cline Group affiliates. From June 2004 untilPrior to joining the Cline Group, Mr. Fifield worked at RCF Management LLC,Resource Capital Funds, a private equity firm focused on metals and mining, in 2004 and 2005. From 1997 to 2000, Mr. Fifield worked in various positions with UBS Warburg, focusing on metals and mining. While at RCF Management, he also served as President of Basin Perlite Company from August 2005 to October 2005. Mr. Fifield received his MBA from The University of Pennsylvania’s Wharton School of Business, which he attended from 2002 through 2004.minerals.
Robert B. Karn IIIjoined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Karn brings extensive financial and coal industry experience to the board of directors. He currently is a consultant and serves on the Board of Directors of various entities. He was the partner in charge of the coal mining practice worldwide for Arthur Andersen from 1981 until his retirement in 1998. He retired as Managing Partner of the St. Louis office’s Financial and Economic Consulting Practice. Mr. Karn is a Certified Public Accountant, Certified Fraud Examiner and has served as president of numerous organizations. He also currently serves on the Board of Directors of Peabody Energy Corporation, Kennedy Capital Management, Inc. and the Board of Trustees of Fiduciary Claymore MLP Opportunity Fund.numerous publicly listed closed-end, exchange traded funds of the Guggenheim family of funds.
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S. Reed Morianjoined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive business experience having served as Chairman and Chief Executive Officer of several companies since the early 1980s and serving on the board of other companies. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian worked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief Executive Officer from 1981 to 2006. He has also served as Chairman, Chief Executive Officer and President of DX Holding Company since 1989. He formerly served on the Board of Directors for the Federal Reserve Bank of Dallas-Houston Branch from April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March 2005 until April 2009.
W. W. Scott, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Scott has extensive experience both as a commercial banker and as a Chief Financial Officer. Mr. Scott joined Mr. Robertson’s various companies in the mid-1980s, and retired in 1999. Mr. Scott was Executive Vice President and Chief Financial Officer of Quintana Minerals Corporation from 1985 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation from 1986 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Great Northern Properties Limited Partnership from 1992 to 1999. Since 1999, he has continued to serve as a director of the general partner of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation.
Stephen P. Smithjoined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive public company financial experience in the power and energy industries to the board of directors. Mr. Smith has been the Executive Vice President and Chief Financial Officer for NiSource, Inc. since June 2008. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc, including Senior Vice President — Shared Services from January 2008 to June 2008, Senior Vice President and Treasurer from January 2004 to December 2007, and Senior Vice President — Finance from April 2003 to December 2003. From November 2000 to January 2003, Mr. Smith served as President and Chief Operating Officer — Corporate Services for NiSource Inc. Prior to joining NiSource, Mr. Smith served as Deputy Chief Financial Officer for Columbia Energy Group from November 1999 to November 2000 and Chief Financial Officer for Columbia Gas Transmission Corporation and Columbia Gulf Transmission Company from 1996 to 1999.
Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings extensive experience in the aggregates and coal mine development industry to the board of directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the late 1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer, contractor and contractoroil terminal developer/operator in theMid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with Vecellio & Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996 to November 2002. Mr. Vecellio is the former Chairman of the American Road and Transportation Builders and is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations.
Corporate Governance
Board Attendance and Executive Sessions
The Board of Directors met tennine times in 2009.2010. During that period, every director attended all of the board meetings, with the exception of Mr. Fifield, who missed two meetingswas excused from one meeting that involved discussions of acquisitionsan acquisition from the Cline Group, and Messrs. Morian, Carmichael, Vecellio and Scott,Smith, who each missed one meeting. Pursuant to our Corporate Governance Guidelines, the non-management directors meet in executive session on a quarterly basis. During 2009,2010, our non-management directors met in executive session four times. The presiding director of these meetings was David Carmichael, the Chairman of our Compensation, Nominating and Governance Committee, or CNG Committee. In addition, our independent directors met one
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time in executive session in 2009.2010. Mr. Carmichael was the presiding director at this meeting. Interested parties may communicate with our non-management directors by writing a letter to the Chairman of the CNG Committee, NRP Board of Directors, 601 Jefferson St., Suite 3600, Houston, Texas 77002.
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Independence of Directors
The Board of Directors has affirmatively determined that Messrs. Blakely, Carmichael, Karn, Smith and Vecellio are independent based on all facts and circumstances considered by the board, including the standards set forth in Section 303A.02(a) of the New York Stock Exchange’s listing standards. Although we had a majority of independent directors in 2009,2010, because we are a limited partnership as defined in Section 303A of the New York Stock Exchange’s listing standards, we are not required to do so. The Board has an Audit Committee, Compensation, Nominating and Governance Committee and Conflicts Committee, each of which is staffed solely by independent directors. Our Audit Committee is comprised of Robert B. Karn III, who serves as chairman, Robert T. Blakely, Stephen P. Smith and David M. Carmichael. Mr. Karn, Mr. Smith and Mr. Blakely are “Audit Committee Financial Experts” as determined pursuant to Item 407 ofRegulation S-K. In addition to his service on our audit committee and the audit committee for Westlake Chemical Corporation, in 2009 Mr. Blakely joined the audit committees of two additional public companies. In accordance with the rules of the New York Stock Exchange, our Board of Directors has made the determination that Mr. Blakely’s service on four audit committees does not impair his ability to serve effectively on our audit committee.
Report of the Audit Committee
Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements of the New York Stock Exchange. The Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements.
During the year 2009,2010, at each of its meetings, the Committee met with the senior members of our financial management team, our general counsel and our independent auditors. The Committee had private sessions at certain of its meetings with our independent auditors at which candid discussions of financial management, accounting and internal control issues took place.
The Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 20092010 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our financial reporting.
Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference for conservative policies when a range of accounting options is available.
The Committee also discussed with the independent auditors other matters required to be discussed by the auditors with the Committee by PCAOB Auditing Standard AU Section 380,Communication With Audit Committees.The Committee received and discussed with the auditors their annual written report on their independence from the partnership and its management, which is made under Rule 3526,Communication With Audit Committees Concerning Independence,and considered with the auditors whether the provision of non-audit services provided by them to the partnership during 20092010 was compatible with the auditors’ independence.
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In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Committee reviews our quarterly and annual reporting onForm 10-Q andForm 10-K prior to filing with the Securities and Exchange Commission. In 2009,2010, the Committee also reviewed quarterly earnings announcements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Committee relies on the work and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report,
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express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting principles.
In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, and the Board has approved, that the audited financial statements be included in our Annual Report onForm 10-K for the year ended December 31, 2009,2010, for filing with the Securities and Exchange Commission.
Robert B. Karn III, Chairman
Robert T. Blakely
Stephen P. Smith
David M. Carmichael
Compensation, Nominating and Governance Committee Authority
Executive officer compensation is administered by the CNG Committee, which is comprised of four members. Mr. Carmichael, the Chairman, and Mr. Karn have served on this committee since 2002, Mr. Blakely joined the committee in early 2003, and Mr. Vecellio joined the committee in 2007. The CNG Committee has reviewed and approved the compensation arrangements described in the Compensation Discussion and Analysis section of thisForm 10-K. Our board of directors appoints the CNG Committee and delegates to the CNG Committee responsibility for:
| • | reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates to our business; | |
| • | reviewing and recommending the annual and long-term incentive plans in which our executive officers participate; and | |
| • | reviewing and approving compensation for the board of directors. |
Our board of directors has determined that each committee member is independent under the listing standards of the New York Stock Exchange and the rules of the Securities and Exchange Commission.
Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the design and implementation of compensation programs for directors and executive officers and other data that the CNG Committee considers as appropriate. In addition, the CNG Committee has the sole authority to retain and terminate any outside counsel or other experts or consultants engaged to assist it in the evaluation of compensation of our directors and executive officers.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities and Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of their equity securities. These people are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required other than one Form 5 for Mr. Karn,in 2010, we believe that our officers and directors and persons who beneficially own more than ten percent of a registered class of our equity securities complied with all filing requirements with respect to transactions in our equity securities during 2009,2010, with the exception of Adena Minerals and Mr. Scott, who each had one late Form 4.
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Partnership Agreement
Investors may view our partnership agreement and the amendments to the partnership agreement on our website atwww.nrplp.com. The partnership agreement and the amendments are also filed with the Securities and Exchange Commission and are available in print to any unitholder that requests them.
Corporate Governance Guidelines and Code of Business Conduct and Ethics
We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that applies to our management, and complies with Item 406 ofRegulation S-K. Our Corporate
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Governance Guidelines and our Code of Business Conduct and Ethics are available on the internet atwww.nrplp.comand are available in print upon request.
NYSE Certification
Pursuant to Section 303A of the NYSE Listed Company Manual, in 2009,2010, Corbin J. Robertson, Jr. certified to the NYSE that he was not aware of any violation by the Partnership of NYSE corporate governance listing standards.
| Item 11. | Executive Compensation |
Compensation Discussion and Analysis
Overview
As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. We have no employees, and our executive officers based in Houston, Texas are employed by Quintana Minerals Corporation and our executive officers based in Huntington, West Virginia are employed by Western Pocahontas Properties Limited Partnership, both of which are our affiliates. For a more detailed description of our structure, please see “Item 1. Business — Partnership Structure and Management” in thisForm 10-K. Although our executives’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse those companies based on the time allocated to NRP by each executive officer. Our reimbursement for the compensation of executive officers is governed by our partnership agreement.
Executive Officer Compensation Strategy and Philosophy
Under our partnership agreement, we are required to distribute all of our available cash each quarter. Our primary business objective is to generate cash flows at levels that can sustain regularlong-term quarterly increases in the cash distributions paid to our investors. Our executive officer compensation strategy has been designed to motivate and retain our executive officers and to align their interests with those of our unitholders. Our primary objective in determining the compensation of our executive officers is to encourage them to build the partnership in a way that ensures long-term increased cash distributions to our unitholders and growth in our asset base while maintaining the long-term stability of the partnership. We do not tie our compensation to achievement of specific financial targets or fixed performance criteria, but rather evaluate the appropriate compensation on an annual basis in light of our overall business objectives.
In accordance with our objective of sustaining and increasing the quarterly distribution over the long-term, we believe that optimal alignment between our unitholders and our executive officers is best achieved by compensating our executive officers through sharing a percentage of the incentive distribution rightsdistributions received by our general partner and through distribution equivalent rights tied to long-term equity-based compensation. Our compensation for executive officers consists of four primary components:
| • | base salaries; | |
| • | annual cash incentive awards, including bonuses and cash payments made by our general partner based on a percentage of the cash it receives from |
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| • | long-term equity incentive compensation; and | |
| • | perquisites and other benefits. |
Mr. Robertson does not receive a salary or an annual bonus in his capacity as CEO. Rather, for the reasons discussed in greater detail below, Mr. Robertson is compensated exclusively through long-term phantom unit grants awarded by the CNG Committee and through sharing a percentage of the incentive distribution rights owneddistributions received by ourthe general partner and its affilitates.partner. Mr. Robertson also directly or indirectly owns in excess of 25%20% of the outstanding units of NRP, and thus his interests are directly aligned with our unitholders.
In November and December 2009,2010, our CNG Committee reviewed the performance of the executive officers and the amount of time expected to be spent by each NRP officer on NRP business. All of our executive officers other than Mr. Robertson spend nearly 90% or more of their time on NRP matters and NRP bears the allocated cost of their time spent on NRP matters. Mr. Robertson has historically spent approximately
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50% of his time on NRP matters. Based on its review, the CNG Committee approved an average increase of 3.5% in the salaries at the same levels as in 2009 for each of the executive officers in 2011 other than Mr. Robertson.
In February 2010,2011, the CNG Committee met to approve the year-end bonuses and long-term incentive awards for the executive officers. The CNG Committee considered the performance of the partnership, the performance of the individuals and the outlook for the future in determining the amounts of the awards. Because we are a partnership, tax and accounting conventions make it more costly for us to issue additional common units or options as incentive compensation. Consequently, we have no outstanding options or restricted units and have no plans to issue options or restricted units in the future. Instead, we have issued phantom units to our executive officers that are paid in cash based on the average closing price of our common units for the20-day trading period prior to vesting. The phantom units typically vest four years from the date of grant. In connection with the phantom unit awards granted in 2008, 2009 and 2010,2008-2011, the CNG Committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on our common units. The DERs have a four-year vesting period. Through these awards, each executive officer’s interest is aligned with those of our unitholders in sustaining and increasing our quarterly cash distributions over the long-term, increasing the value of our unit pricecommon units, and maintaining a steady growth profile for NRP.
Role of Compensation Experts
The CNG Committee did not retain any consultants to evaluate compensation of officers or directors in 2009.2010. The CNG Committee historicallyperiodically has utilized consultants every other year to get a basic sense of the market, but has considered the advice of the consultant as only one factor among the other items discussed in this compensation discussion and analysis. The most recent review was conducted in 2008. For a more detailed description of the CNG Committee and its responsibilities, please see “Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance” in thisForm 10-K.
Role of Our Executive Officers in the Compensation Process
Mr. Robertson and Mr. Carter provided recommendations to the CNG Committee in its evaluation of the 20092010 compensation programs for our executive officers. Mr. Carter provided Mr. Robertson with recommendations relating to the executive officers, other than himself, that are based in Huntington. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of the executive officers, including the Houston-based officers other than himself. Mr. Robertson and Mr. Carter relied on their personal experience in setting compensation over a number of years in determining the appropriate amounts for each employee, and considered each of the factors described elsewhere in this compensation discussion and analysis. Mr. Robertson and Mr. Carter attended the CNG Committee meetings at which the committee deliberated and approved the compensation, but waswere excused from the meetings when the CNG Committee discussed histheir compensation. No other named executive officer assumed an active role in the evaluation or design of the 20092010 executive officer compensation programs.
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Components of Compensation
Base Salaries
With the exception of Mr. Robertson, who, as described above, does not receive a salary for his services as Chief Executive Officer, our named executive officers are paid an annual base salary by Quintana and Western Pocahontas for services rendered to us by the executive officers during the fiscal year. We then reimburse Quintana and Western Pocahontas based on the time allocated by each executive officer to our business. The base salaries of our named executive officers are reviewed on an annual basis as well as at the time of a promotion or other material change in responsibilities. The CNG Committee reviews and approves the full salaries paid to each executive officer by Quintana and Western Pocahontas, based on both the actual time allocations to NRP in the prior year and the anticipated time allocations in the coming year. Adjustments in base salary are based on an evaluation of individual performance, our partnership’s overall performance during the fiscal year and the individual’s contribution to our overall performance.
Annual Cash Incentive Awards
Each executive officer, other than Mr. Robertson, participated in two cash incentive programs in 2009.2010. The first program is a discretionary cash bonus award approved in February 20102011 by the CNG Committee
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based on the same criteria used to evaluate the annual base salaries. The bonuses awarded with respect to 20092010 under this program are disclosed in the Summary Compensation Table under the Bonus column. As with the base salaries, there are no formulas or specific performance targets related to these awards. AsAlthough we did not increase the quarterly distribution in 2010, NRP investors that held units from January 1 to December 31 received a resulttotal return of the recession and the lower revenues that NRP generated in 2009, we were only able to raise the distribution by 1% over the course of46%. We outperformed our public guidance for the year, and inexceeded most analyst expectations. In addition, we positioned the third and fourth quarters of 2009, the general partner and the other holders ofpartnership for long-term distribution growth by eliminating the incentive distribution rights, waived their rights to receivethereby lowering the highest splits undercost of capital for future acquisitions. NRP also made several accretive acquisitions during the incentive distribution rights in order to facilitate a large acquisition.year. These factors were considered by the CNG Committee in determining to award lowerhigher bonuses to the executive officers in 20092010 versus 2008.2009.
Under the second cash incentive program, our general partner has set aside 7.5% of the cash distributions it receives on an annual basis with respect to its incentive distribution rights underdistributions on common units held by our partnership agreementgeneral partner for awards to our executive officers, including Mr. Robertson. Although Mr. Robertson has the discretion to determine the amount of the 7.5% that is allocated to each executive officer, the cash awards that our officers receive under this plan are reviewed by the CNG Committee and taken into account when making determinations with respect to salaries, bonuses and long-term incentive awards. Because they are ultimately reimbursed by the general partner and not NRP, the incentive payments made with respect to this program do not have any impact on our financial statements or cash available for distribution to our unitholders. Since the cost of these awards is not borne by NRP, we have not disclosed the amounts of these awards in the Summary Compensation Table, but have included the amounts separately in a footnote to the table. We believe that these awards align the interests of our executive officers directly with our unitholders in consistently increasing our quarterly distributions. As evidence of this alignment, the waiver by the general partner of a portion of its incentive distribution rights in the third and fourth quarters of 2009 reduced the amount of cash available to be awarded to the executive officers under that program.unitholders.
Long-Term Incentive Compensation
At the time of our initial public offering, we adopted the Natural Resource Partners Long-Term Incentive Plan for our directors and all the employees who perform services for NRP, including the executive officers. We consider long-term equity-based incentive compensation to be the most important element of our compensation program for executive officers because we believe that these awards keep our officers focused on the growth of NRP, particularly the sustainability and long-term growth of quarterly distributions and their impact on our unit price, over an extended time horizon.
Consistent with this approach, in 2008 our CNG Committee recommended, and our Board approved, an amendment to our Long-Term Incentive Plan to add distribution equivalent rights as a possible award to be granted under the plan. The distribution equivalent rights are contingent rights, granted in tandem with phantom units, to receive an amount in cash equal to the cash distributions made by NRP with respect to the common units during the period in which the phantom units are outstanding.
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Our CNG Committee has generally approved annual awards of phantom units that vest four years from the date of grant. The amounts included in the compensation table reflect the grant date fair value of the unit awards determined in accordance with Financial Accounting Standards Board stock compensation authoritative guidance. We have structured the phantom unit awards so that our executive officers and directors directly benefit along with our unitholders when our unit price increases, and experience reductions in the value of their incentive awards when our unit price declines.
In connection with its review of incentive compensation in February 2010,2011, the CNG Committee determined not to increase the annual phantom unit grants to anyeach of the named executive officers and approved a lower award in 2010 for Mr. Robertson as compared the award he received in 2009.officers.
Perquisites and Other Personal Benefits
Both Quintana and Western Pocahontas maintain employee benefit plans that provide our executive officers and other employees with the opportunity to enroll in health, dental and life insurance plans. Each of these benefit plans require the employee to pay a portion of the health and dental premiums, with the company paying the remainder. These benefits are offered on the same basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee allocates time to our business.
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Quintana and Western Pocahontas also maintain 401(k) and defined contribution retirement plans. Quintana matches 100% of the first 4.5% of the employee contributions under the 401(k) plan and Western Pocahontas matches the employee contributions at a level of 100% of the first 3% of the contribution and 50% of the next 3% of the contribution. In addition, each company contributes 1/1/12 of each employee’s base salary to the defined contribution retirement plan on an annual basis. As with the other contributions, any amounts contributed by Quintana and Western Pocahontas are reimbursed by us based on the time allocated by the employee to our business. The payments made to Messrs. Carter, Dunlap, Hogan and Wall under the defined contribution plan exceeded $10,000 in each of 2007, 2008, 2009 and 2009,2010, but did not exceed $20,000 for any individual in any year. None of NRP, Quintana or Western Pocahontas maintain a pension plan or a defined benefit retirement plan. As noted in the Summary Compensation Table, in 2007, 2008, 2009 and 20092010 we also reimbursed Quintana and Western Pocahontas for car allowances provided to Messrs. Carter, Dunlap and Wall.
Unit Ownership Requirements
We do not have any policy or guidelines that require specified ownership of our common units by our directors or executive officers or unit retention guidelines applicable to equity-based awards granted to directors or executive officers. As of December 31, 2009,2010, our named executive officers held 231,000254,000 phantom units that have been granted as compensation. In addition, Mr. Robertson directly or indirectly owns in excess of 25%20% of the outstanding units of NRP.
Securities Trading Policy
Our insider trading policy states that executive officers and directors may not purchase or sell puts or calls to sell or buy our units, engage in short sales with respect to our units, or buy our securities on margin.
Tax Implications of Executive Compensation
Because we are a partnership, Section 162(m) of the Internal Revenue Code does not apply to compensation paid to our named executive officers and accordingly, the CNG Committee did not consider its impact in determining compensation levels in 2007, 2008, 2009 or 2009.2010. The CNG Committee has taken into account the tax implications to the partnership in its decision to limit the long-term incentive compensation to phantom units as opposed to options or restricted units.
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Accounting Implications of Executive Compensation
The CNG Committee has considered the partnership accounting implications, particularly the“book-up” cost, of issuing equity as incentive compensation, and has determined that phantom units offer the best accounting treatment for the partnership while still motivating and retaining our executive officers.
Report of the Compensation, Nominating and Governance Committee
The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) ofRegulation S-K with management. Based on the reviews and discussions referred to in the foregoing sentence, the CNG Committee recommended to the board of directors that the Compensation Discussion and Analysis be included in our Annual Report onForm 10-K for the year ended December 31, 2009.2010.
David M. Carmichael, Chairman
Robert B. Karn III
Robert T. Blakely
Leo A. Vecellio, Jr.
Robert B. Karn III
Robert T. Blakely
Leo A. Vecellio, Jr.
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