NATURAL RESOURCE PARTNERS LP - Quarter Report: 2013 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

For the quarterly period ended September 30, 2013

OR

Commission file number: 001-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

601 Jefferson Street, Suite 3600

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 751-7507

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

At November 7, 2013 there were 109,812,408 Common Units outstanding.

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TABLE OF CONTENTS

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Forward-Looking Statements

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

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

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

You should not put undue reliance on any forward-looking statements. See “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 for important factors that could cause our actual results of operations or our actual financial condition to differ.

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Part I. Financial Information

Item 1. Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands, except per unit data)

The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands, except unit data)

The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for future periods.

You should refer to the information contained in the footnotes included in Natural Resource Partners L.P.’s 2012 Annual Report on Form 10-K in connection with the reading of these unaudited interim consolidated financial statements.

Natural Resource Partners L.P. (the “Partnership”) engages principally in the business of owning, managing and leasing mineral properties in the United States. The Partnership owns coal reserves in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. The Partnership also owns aggregate reserves in several states across the country. The Partnership does not operate any mines on its properties, but leases reserves to experienced operators under long-term leases that grant the operators the right to mine the Partnership’s reserves in exchange for royalty payments. Lessees are generally required to make payments based on the higher of a percentage of the gross sales price or a fixed royalty per ton, in addition to a minimum payment.

The Partnership also owns various oil and gas interests that are located principally in the Appalachian Basin, Louisiana, Oklahoma, and the Williston Basin in North Dakota and Montana, and the Partnership manages infrastructure assets through its ownership of preparation plants and coal handling facilities. In January 2013, the Partnership purchased a non-controlling equity interest in OCI Wyoming, L.P. (“OCI Wyoming”), which operates a trona ore mining operation and a soda ash refinery in the Green River Basin, Wyoming. See “Note 3. Equity and Other Investments” for more information concerning this acquisition.

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.

Reclassification

Certain reclassifications have been made to the prior year’s financial statements.

Equity Investments

The Partnership accounts for non-marketable investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if the Partnership has an ownership interest representing between 20% and 50% of the voting stock of the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investment and the proportionate share of earnings or losses and distributions. Furthermore, under the equity method of accounting, an investee company’s accounts are not reflected within the Partnership’s Consolidated Balance Sheets and Statements of Comprehensive Income. However, the Partnership’s carrying value in an equity method investee company is reflected in the caption “Equity and other unconsolidated investments” in the Partnership’s Consolidated Balance Sheets. The Partnership’s share of the earnings or losses of the investee company is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity and other unconsolidated investment income. These earnings are generated from natural resources, which are considered part of the Partnership’s core business activities consistent with its directly owned revenue generating activities.

The Partnership accounts for its non-marketable equity investments using the cost method of accounting if its ownership interest does not provide the ability to exercise significant influence over the investee or if the investment is not determined to be in-substance common stock. The inability to exert significant influence is generally presumed if the investment is less than 20% of the investee’s voting securities.

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The Partnership evaluates its equity investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. No impairment losses have been recognized as of September 30, 2013.

Recent Accounting Pronouncements

In February 2013, the FASB amended the comprehensive income reporting requirements to require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. The amendment requires an entity to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The adoption did not have a material impact on the financial statements.

Other accounting standards that have been issued 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 or cash flows.

Abraxas. On August 9, 2013, the Partnership completed the acquisition of non-operated working interests in 13,515 net acres within the Bakken/Three Forks play in North Dakota and Montana from Abraxas Petroleum. The Partnership accounted for the transaction in accordance with the FASB’s provisions for business combinations. The identification of all assets acquired and liabilities assumed as well as the valuation process required for the allocation of the purchase price is not complete. Pending the final allocation, the assets acquired of approximately $38.3 million are included in mineral rights in the accompanying Consolidated Balance Sheets.

In the first quarter of 2013, the Partnership acquired non-controlling equity interests in OCI Co and OCI Wyoming comprised of a 48.51% general partner interest in OCI Wyoming and 20% of the common stock and 100% of the preferred stock of OCI Co. On the acquisition date, OCI Co was a conduit entity with its only asset a 1% interest in OCI Wyoming together with the right to receive an annual priority distribution. On July 18, 2013, the OCI companies were restructured resulting in the elimination of the common and preferred stock interests and an increase in the Partnership’s interest in OCI Wyoming to 49%. The restructuring did not have a material impact on the operations, management, control or projected cash flows from the acquired OCI interests.

OCI Wyoming’s operations consist of the mining of trona ore, which, when refined, becomes soda ash. All soda ash is sold through an affiliated sales agent to various domestic and European customers and to American Natural Soda Ash Corporation for export primarily to Asia and Latin America. All mining and refining activities take place in one facility located in the Green River Basin, Wyoming. These investments were acquired from Anadarko Holding Company and its subsidiary, Big Island Trona Company for $292.5 million. The acquisition was funded through a $200 million term loan, the issuance of $76.5 million in equity (including a general partner contribution of $1.5 million), and $16 million in cash. The acquisition agreement provides for a net present value of up to $50 million in cumulative additional contingent consideration payable by the Partnership should certain performance criteria be met as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015.

The Partnership has engaged a valuation specialist to assist in identifying and valuing the assets and liabilities of OCI Wyoming at the date of acquisition, including the land, mine, plant and equipment as well as identifiable intangible assets, if any. Included in preliminary fair value adjustments, based on the most recent estimates, is an increase in the Partnership’s proportionate fair value of property, plant and equipment of $78.7 million. Under the equity method of accounting, this amount is not reflected individually in the accompanying consolidated financial statements but is used to determine periodic charges to amounts reflected as income earned from the equity investments. For the quarter and nine months ended September 30, 2013, amortization of purchase adjustments of $0.7 and $1.9 million was recorded by the Partnership. In July 2013, the Partnership received a $44.8 million special distribution associated with OCI Wyoming’s refinancing transaction. Until the valuations are complete, the remainder of the excess of the purchase price over the estimated fair value of the interests acquired has been attributed to goodwill; which is not subject to amortization. The allocation of the purchase price to the assets and liabilities is preliminary and subject to further adjustment, which may be material.

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The following summarized financial information as of September 30, 2013 and the results of operations for the three and nine-month periods then ended were taken from the OCI-prepared unaudited financial statements.

Operating results:

Balance Sheet information:

The Partnership’s plant and equipment consist of the following:

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The Partnership’s mineral rights consist of the following:

Amounts recorded as intangible assets along with the balances and accumulated amortization are reflected in the table below:

The estimates of future amortization expense relating to intangible assets for the periods indicated below are based on current mining plans, which are subject to revision in future periods.

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As used in this Note 8, references to “NRP LP” refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to “Opco” refer to NRP (Operating) LLC and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP LP. NRP Finance Corporation (NRP Finance) is a wholly owned subsidiary of NRP LP and a co-issuer with NRP LP on the 9.125% senior notes.

Long-term debt consists of the following:

NRP LP Debt

Senior Notes. In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300 million of 9.125% senior notes at an offering price of 99.007% of par value. Net proceeds after expenses from the issuance of the senior notes of approximately $289.0 million were used to repay all of the outstanding borrowings under Opco’s revolving credit facility and $91.0 million of Opco’s term loan. The senior notes call for semi-annual interest payments on April 1 and October 1 of each year, beginning on April 1, 2014. The notes will mature on October 1, 2018.

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The indenture for the senior notes contains covenants that, among other things, limit the ability of the NRP LP and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the indenture, NRP LP and certain of its subsidiaries generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as defined in the indenture) is at least 2.0 to 1.0 for the four preceding full fiscal quarters. The ability of NRP LP and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of NRP LP and certain of its subsidiaries that is senior to NRP LP’s unsecured indebtedness exceeds certain thresholds.

Opco Debt

Senior Notes. Opco made principal payments of $87.0 million on its senior notes during the nine months ended September 30, 2013. The Opco senior note purchase agreement contains covenants requiring Opco to:

The 8.38% and 8.92% senior notes also provide that in the event that Opco’s 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.

Revolving Credit Facility. The weighted average interest rates for the debt outstanding under Opco’s revolving credit facility for the nine months ended September 30, 2013 and year ended December 31, 2012 were 2.23% and 2.09%, respectively. Opco incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.18% to 0.40% per annum. The facility includes an accordion feature whereby Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms.

Opco’s revolving credit facility contains covenants requiring Opco to maintain:

Term Loan Facility. During the first quarter of 2013, Opco also issued $200 million in term debt. The weighted average interest rate for the debt outstanding under the term loan for the nine months ended September 30, 2013 was 2.45%. Opco repaid $101 million in principal under the term loan during the third quarter of 2013. Repayment terms call for the remaining outstanding balance of $99 million to be paid on January 23, 2016. The debt is unsecured but guaranteed by the subsidiaries of Opco.

Opco’s term loan contains covenants requiring Opco to maintain:

NRP Oil and Gas Debt

Revolving Credit Facility. In August 2013, NRP Oil and Gas entered into a 5-year, $100 million senior secured, reserve-based revolving credit facility in order to fund capital expenditure requirements related to the development of the non-operated working interests in oil and gas assets located in the Bakken/Three Forks play acquired on August 9, 2013. The credit facility has an initial borrowing base of $8.0 million and is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. At September 30, 2013, there were no borrowings outstanding under the credit facility.

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Indebtedness under the NRP Oil and Gas credit facility bears interest, at the option of NRP Oil and Gas, at either:

NRP Oil and Gas will incur a commitment fee on the unused portion of the borrowing base under the credit facility at a rate ranging from 0.375% to 0.50% per annum.

The NRP Oil and Gas credit facility contains certain covenants, which, among other things, require the maintenance of:

Consolidated Principal Payments

The consolidated principal payments due are set forth below:

NRP LP, Opco and NRP Oil and Gas were in compliance with all terms under their long-term debt as of September 30, 2013.

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 except for the accounts receivable – affiliates relating to the Sugar Camp override and Taggart preparation plant sale that includes both current and long-term portions. The Partnership’s cash and cash equivalents include money market accounts and are considered a Level 1 measurement. The fair market value and carrying value of the contractual override, Taggart note receivable and long-term senior notes are as follows:

The fair value of the Sugar Camp override, Taggart plant sale and long-term debt 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 and term loan are both variable rate debt, their fair values approximate their carrying amounts.

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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 technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. The Partnership had an amount payable to Quintana Minerals Corporation of $0.7 million at September 30, 2013 for services provided by Quintana to the Partnership.

The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as follows:

The Partnership also leases an office building in Huntington, West Virginia from Western Pocahontas Properties and pays $0.6 million in lease payments each year through December 31, 2018.

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. At September 30, 2013, Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owned a 31% interest in the Partnership’s general partner, as well as 4,917,548 common units.

Revenues from the Cline affiliates are as follows:

At September 30, 2013, the Partnership had amounts due from Cline affiliates totaling $61.7 million, of which $56.7 million was attributable to agreements relating to Sugar Camp. The Partnership has received $69.2 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $16.3 million was received in the current year.

During 2013, the Partnership recognized an $8.1 million gain on a reserve swap in Illinois with Williamson Energy. This gain is reflected in the table above in the “Other revenue” line. The fair value of the reserves was estimated using Level 3 cash flow approach. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates. The tons received will be fully mined during 2013, while the tons exchanged are not included in the current mine plans.

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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 the Partnership’s conflicts policy.

At September 30, 2013, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp., a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Revenues from Corsa are as follows:

The Partnership also had accounts receivable totaling $0.4 million from Corsa at September 30, 2013.

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.

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 September 30, 2013. The Partnership is not associated with any environmental contamination that may require remediation costs. During the second quarter of 2013, several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including selenium, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. A subsidiary of NRP was named as a defendant in one of these lawsuits, but the suit has been dismissed. While it is too early to determine the merits or predict the outcome of any of these lawsuits, any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.

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Revenues from lessees that exceeded ten percent of total revenues and other income for the periods are presented below:

In the first nine months of 2013, the Partnership derived over 42% of its total revenues and other income from the two companies listed above. The first nine months of 2013 revenues received from the Cline Group include $8.1 million in revenues recorded in connection with a reserve swap at Cline’s Williamson mine. Excluding the revenues from the reserve swap, revenues from the Cline Group accounted for approximately $60.3 million, or 23% of the Partnership’s total revenues and other income for the first nine months of 2013. The Partnership has a significant concentration of revenues with Cline and Alpha, although in most cases, with the exception of the Williamson mine, the exposure is spread out over a number of different mining operations and leases. Cline’s Williamson mine was responsible for approximately 14% of the Partnership’s total revenues and other income for the first nine months of 2013, which amount includes the $8.1 million of revenue recorded from the reserve swap. Excluding revenues from the reserve swap, revenues from the Williamson mine accounted for approximately 11% of the Partnership’s total revenues and other income for the first nine months of 2013.

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, Nominating and Governance (“CNG”) 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 CNG 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 last 20 trading days prior to the vesting date. The CNG 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 CNG Committee provides otherwise.

A summary of activity in the outstanding grants during 2013 is as follows:

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 volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.14% to 0.63% and 27.65% to 32.46%, respectively at September 30, 2013. The Partnership’s average distribution rate of 7.24% and historical forfeiture rate of 4.20% were used in the calculation at September 30, 2013. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $0.6 million and

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$1.2 million and $7.5 million and $3.6 million for the three and nine months ended September 30, 2013 and 2012, respectively. In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $7.0 million and $6.6 million were made during the nine month period ended September 30, 2013 and 2012, respectively.

In connection with the phantom unit awards granted since February 2008, the CNG 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. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.

The unaccrued cost, associated with the unvested outstanding grants and related DERs at September 30, 2013 was $10.4 million.

On August 14, 2013, the Partnership paid a quarterly distribution $0.55 per unit to all holders of common units on August 5, 2013.

The following represents material events that have occurred subsequent to September 30, 2013 through the time of the Partnership’s filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission:

Distributions

On October 22, 2013, the Partnership declared a distribution of $0.55 per unit to be paid on November 14, 2013 to unitholders of record on November 5, 2013.

Acquisition

On October 30, 2013, we signed a definitive agreement to acquire non-operated working interests in oil and gas properties in the Williston Basin of North Dakota, including properties producing from the Bakken/Three Forks play, from Sundance Energy, Inc. for $35.5 million, subject to customary purchase price adjustments at closing. Upon entering into the agreement, we paid a $3.6 million cash deposit into escrow.

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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 and the financial statements and footnotes included in the Natural Resource Partners L.P. Annual Report on Form 10-K for the year ended December 31, 2012, as filed on February 28, 2013.

As used in this Item 2, unless the context otherwise requires: “we,” “our” and “us” refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to “NRP” and “Natural Resource Partners” refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to “Opco” refer to NRP (Operating) LLC and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation (“NRP Finance”) is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes.

Executive Overview

Our Business

We engage principally in the business of owning, managing and leasing mineral properties in the United States. We own coal reserves in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. As of December 31, 2012, we owned or controlled approximately 2.4 billion tons of proven and probable coal reserves. 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. We also own and manage infrastructure assets that generate additional revenues for our company, particularly in the Illinois Basin.

In recent years, we have made a concerted effort to diversify our business. In connection with this effort, we have acquired approximately 500 million tons of aggregate reserves located in a number of states across the country. In our coal and aggregate 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, which varies 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.

We have also acquired various interests in oil and gas properties that are located principally in the Appalachian Basin, Louisiana, Oklahoma, and in the Williston Basin in North Dakota and Montana. Oil and gas royalty revenues include production payments as well as bonus payments. Oil and gas royalty revenues are recognized on the basis of hydrocarbons sold by lessees and the corresponding revenues from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some leases are subject to minimum annual payments or delay rentals. Revenues related to our non-operated working interests in oil and gas assets are recognized on the basis of our net revenue interests in hydrocarbons produced. We also have capital expenditure obligations associated with the non-operated working interests.

In 2013, we have made significant strides in our diversification effort through the following acquisitions:

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For the nine months ended September 30, 2013, we recognized $98.4 million of revenues and other income from sources other than coal royalties, which primarily consisted of equity income from our investment in OCI Wyoming, oil and gas royalties, aggregates royalties, overriding royalties (which include coal and aggregates overrides), minimums recognized as revenue, and processing and transportation fees. The revenues that we recognize from minimums and processing/transportation are largely derived from coal-related businesses.

Our Current Liquidity Position

In September 2013, NRP, together with NRP Finance as co-issuer, sold $300.0 million of 9.125% Senior Notes due 2018 at an issue price of 99.007% of par value for net proceeds of $289 million. We used the net proceeds of the offering to repay all outstanding borrowings under Opco’s revolving credit facility. Opco’s revolving credit facility does not mature until August 2016 and, as of September 30, 2013, Opco had $300 million in available capacity under the facility. In August 2013, NRP Oil and Gas entered into a senior secured, reserve-based revolving credit facility with an initial $8.0 million borrowing base. As of September 30, 2013, NRP Oil and Gas had the full $8.0 million available for borrowing under its revolving credit facility. In addition to the amounts available under our revolving credit facilities, we had $99.7 million in cash at September 30, 2013. We believe that the combination of our capacity under our revolving credit facilities and our cash on hand gives us enough liquidity to meet our current financial needs. We typically access the capital markets to refinance amounts outstanding under our revolving credit facilities as we approach the limits under those facilities, the timing of which depends on the pace and size of our acquisition program and development capital expenditures associated with our oil and gas business.

We refinanced $7.0 million in principal payments on Opco’s senior notes during the third quarter of 2013. Rather than pay the Opco senior notes principal payments that are due over the next twelve months with cash from operations, we might refinance some or all of these obligations as they come due.

We used $91.0 million of net proceeds from the September 2013 senior notes offering to repay principal on Opco’s term loan. We also used a portion of the proceeds from the July 2013 $44.8 million special distribution from OCI Wyoming to repay $10.0 million of principal on Opco’s term loan. Accordingly, Opco’s next principal repayment obligation on the term loan is not until January 2016, when Opco will be required to repay the remaining principal amount outstanding thereunder of $99.0 million.

Current Results/Market Outlook

Our total revenues and other income for the first nine months of 2013 were $263.4 million, which was down approximately 5% when compared to the $276.7 million in total revenues and other income received for the first nine months of 2012. Although our total revenues and other income were only down 5%, our coal royalty revenues were down approximately 15% and our Central Appalachian coal royalty revenues were down over 32% in the same periods. We anticipated these declines and continue to see the benefits of our diversification efforts, as our coal royalty revenues from the Illinois Basin were up 17% in the first nine months of 2013, our investment in OCI Wyoming contributed $22.2 million in other income, and our oil and gas revenues increased 45% and continue to ramp up. As a result of these efforts, our distributable cash flow increased by 13% over the first nine months of 2012, primarily due to the $72.9 million in distributions that we received from OCI during the nine months ended September 30, 2013.

The decline in Central Appalachian coal royalty revenues resulted from continued weakness in both the metallurgical and steam markets, where prices remain depressed. While the outlook for the high cost Central Appalachian steam coal is challenging due to federal government regulations combined with low natural gas prices, we continue to have substantial exposure to metallurgical coal, from which we derived approximately 42% of our coal royalty revenues and 30% of the related production in the first nine months of 2013. The fourth quarter 2013 benchmark price for metallurgical coal is $152 per metric ton, which is up from the third quarter benchmark price of $145 per metric ton. The metallurgical coal recovery will not be a rapid one, but the global demand for steel continues to increase, and NRP will benefit as this market steadily improves. In addition, the Illinois Basin continues to increase production and is displacing Central Appalachian coal at some utilities. We are benefitting from the Illinois Basin growth through our relationship with Foresight Energy and the Cline Group.

OCI Wyoming’s soda ash business has performed as we projected over the first nine months of 2013, but the increased liquidity associated with a refinancing transaction has resulted in higher than expected cash distributions to NRP in 2013, including a $44.8 million special distribution in July 2013. On a normalized basis, as a result of the OCI Resources LP initial public offering completed in September 2013, NRP anticipates receiving approximately $40.0 million per year of distributions from the OCI investment.

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Growth Through Acquisitions

In 2012, we spent approximately $240 million to acquire additional assets that will help secure the future growth of the partnership. Included in these acquisitions were additional steam coal reserves and transportation infrastructure in Illinois, oil and gas mineral rights in Oklahoma, an overriding royalty on oil and gas reserves in the liquids-rich portion of the Marcellus Shale play, and an overriding royalty on frac sand reserves in Wisconsin. These efforts are reflective of our management’s desire to continue to grow and diversify our assets and attempt to ensure the stability of future revenues and distributions to our unitholders.

In the first ten months of 2013, we continued to diversify our holdings through the acquisition of the interests in the OCI Wyoming soda ash business for $292.5 million, the acquisition of non-operated working interests in producing oil and gas properties in the Bakken/Three Forks play in the Williston Basin from Abraxas Petroleum Corporation for approximately $38.3 million, and the execution of a definitive agreement to acquire non-operated working interests in producing oil and gas properties in the Williston Basin, including properties producing from the Bakken/Three Forks play, from Sundance Energy, Inc. for approximately $35.5 million, subject to customary purchase price adjustments. We expect the Sundance acquisition to close in December 2013.

Political, Legal and Regulatory Environment

The political, legal and regulatory environment continues to be difficult for the coal industry. The Environmental Protection Agency (“EPA”) has used its authority to create significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coal operators. Furthermore, the federal courts have recently handed down several decisions that are adverse to the coal industry and, in a June 2013 speech, President Obama outlined his climate change policies, which include an initiative to limit carbon emissions by existing coal-fired utilities. In September 2013, EPA released proposed new source performance standards for greenhouse gas emissions from new fossil fuel-fired electric generating units. The effect of the proposed rules is that partial carbon capture and sequestration will be necessary to meet the emission standards for carbon dioxide for new fossil fuel-fired power plants. EPA is expected to issue proposed regulations on existing fossil fuel-fired power plants in June 2014. We expect that EPA’s proposed regulations for both new and existing power plants will negatively affect the viability of coal-fired power generation, which will ultimately reduce coal consumption and the production of coal from our properties.

In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators, as well as challenging permits issued by the Army Corps of Engineers. During the second quarter of 2013, several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including selenium, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. A subsidiary of NRP was named as a defendant in one of these lawsuits, but the suit has been dismissed. While it is too early to determine the merits or predict the outcome of any of these lawsuits, any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.

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, distributions from unconsolidated investments, proceeds from sale of assets and returns on direct financing lease and contractual override. 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 us as for other companies. A reconciliation of distributable cash flow to net cash provided by operating activities is set forth below.

We have historically reduced our distributable cash flow by the amount of cash we have reserved for principal payments due on our senior notes in the next calendar year. However, to present our distributable cash flow more in line with MLP practice and because we intend to refinance some or all of the principal payments that are due in 2013 and 2014, beginning with our 2013 presentation, we no longer reduce distributable cash flow by reserves for future principal payments. We have changed our three and nine months ended September 30, 2012 calculations in the table below to be comparable with our presentation for 2013.

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Reconciliation of GAAP “Net cash provided by operating activities”

to Non-GAAP “Distributable cash flow”

Recent Acquisitions

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

Sundance. In October 2013, we signed a definitive agreement to acquire non-operated working interests in oil and gas properties in the Williston Basin of North Dakota, including properties producing from the Bakken/Three Forks play, from Sundance Energy, Inc. for approximately $35.5 million, subject to customary purchase price adjustments at closing.

Abraxas. In August 2013, we acquired non-operated working interests in producing oil and gas properties in the Bakken/Three Forks play in the Williston Basin of North Dakota and Montana from Abraxas Petroleum Corporation for $38.3 million.

OCI Wyoming. In January 2013, we acquired a non-controlling equity interest in OCI Wyoming from Anadarko Holding Company and its subsidiary, Big Island Trona Company for $292.5 million. The acquisition agreement provides for up to $50 million in additional contingent consideration payable by us should certain performance criteria be met as defined in the purchase and sales agreement in any of 2013, 2014 or 2015.

Marcellus Override. In December 2012, we acquired an overriding royalty interest on approximately 88,000 net acres of overriding royalty interests in oil and gas reserves located in the Marcellus Shale for $30.3 million.

Hi-Crush Override. In October 2012, we acquired an overriding royalty interest in frac sand reserves located on approximately 561 acres near Wyeville, Wisconsin for approximately $15.0 million.

Colt. Between September 2009 and September 2012, we acquired approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the Cline Group, for a total purchase price of $255 million.

Oklahoma Oil and Gas. From December 2011 through June 2012, we acquired approximately 19,200 net mineral acres located in the Mississippian Lime oil play in Northern Oklahoma for $63.9 million.

Sugar Camp. In March 2012, we acquired the rail loadout associated infrastructure assets for $50.0 million and a contractual overriding royalty for $8.9 million interest on certain tonnage at the Sugar Camp mine in Illinois. The rail loadout and infrastructure assets were purchased from Sugar Camp Energy, LLC and the contractual overriding royalty interest was purchased from Ruger, LLC, both affiliates of the Cline Group.

Litz-Moore. In March 2012, we acquired metallurgical coal reserves adjacent to current NRP holdings in Virginia for $2.8 million.

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Results of Operations

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

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Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 64% and 75% of our total revenues and other income for the three month periods ended September 30, 2013 and 2012, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

Appalachia. Coal royalty revenues decreased $18.7 million or 36% in the three-month period ended September 30, 2013 compared to the same period of 2012, while production decreased 0.7 million tons or 8%.

As a result of the difficult coal markets, production from our properties in the Central Appalachian region has declined by 22% as some lessees chose to idle mines or mining units during 2012 and in the first nine months of 2013. In addition, pricing realized by the lessees for both steam and metallurgical coal in Central Appalachia is generally below the levels of the same quarter in 2012, causing a higher percentage decrease in coal royalty revenues compared to the decrease in production.

The Southern Appalachian region also had decreased production and coal royalty revenues, primarily due to lower sales of metallurgical coal from the Oak Grove mine, which were also at a lower royalty rate per ton. In addition, production from two lessees moved from our BLC properties to adjacent properties.

With respect to Northern Appalachia, during the quarter ended September 30, 2013 there was a significant increase in production, but a slight decrease in revenues versus the same period in 2012. The increase in tonnage primarily resulted from production from a 1960s era coal lease where the royalty rate per ton is very low. Also contributing to the increased tonnage was a longwall mine moving onto our property during the quarter. However, the longwall mine moving onto our property generates lower royalty per ton than a separate longwall mine that had lower sales during the quarter, which contributed to the decline in revenues.

Illinois Basin. Production and coal royalty revenues for the three months ended September 30, 2013 increased when compared to the same period in 2012. Increased production from the start of the longwall mining unit and the resulting increased sales from our Hillsboro property were offset by lower sales from the Williamson and Macoupin properties.

Northern Powder River Basin. Coal royalty revenues and production decreased on our Western Energy property due to the normal variations that occur due to the checkerboard nature of ownership. The lessee also realized lower sales prices, which reduced the royalty per ton for the quarter.

Aggregate Royalty Revenues and Production. Aggregate revenues increased 21% and production increased 43% for the quarter ended September 30, 2013, compared to the same quarter for 2012, while prices were 15% lower. While aggregate revenues and production were both an increase for the quarter ended September 30, 2013 when compared to the quarter ended September 30, 2012, the increases came from several properties where the royalty rate per ton was significantly lower than the average royalty rate per ton was in third quarter of 2012. In addition to higher royalty revenues and production, in the quarter ended September 30, 2013, we received a royalty bonus on our Washington property of $0.6 million.

Oil and Gas Royalty Revenues. Oil and gas royalty revenues were higher for the current quarter when compared to the same quarter in 2012. A significant increase in royalties received from our Oklahoma assets, as well as revenues from our Bakken/Three Forks properties, resulted in a $2.6 million, or a 212%, increase in revenues over the same quarter for last year. We do not anticipate our Marcellus assets to contribute materially to our revenues until 2014.

Investment in OCI Wyoming. Income from our investment in the OCI Wyoming soda ash business was $7.2 million for the quarter ended September 30, 2013 and we received cash distributions of $46.0 million, which included a one-time special distribution of $44.8 million associated with a refinancing at OCI Wyoming. During the third quarter, OCI Resources LP, which owns 51% of OCI Wyoming, completed an initial public offering. As a result of this offering and OCI Resources’ obligations to make regular quarterly distributions to its partners, we expect to receive approximately $10.0 million in distributions per quarter in the future. Because our investment in OCI Wyoming occurred at the beginning of 2013 there are no comparable results for the prior year.

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Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012