NATURAL RESOURCE PARTNERS LP - Quarter Report: 2014 June (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 June 30, 2014

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 August 8, 2014 there were 111,250,522 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:

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, 2013 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 for unit information)

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

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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)

(Unaudited)

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

1. Basis of Presentation and Organization

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 six months ended June 30, 2014 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 2013 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. The Partnership owns a non-controlling equity interest in OCI Wyoming LLC (“OCI Wyoming”), which operates a trona ore mining operation and a soda ash refinery in the Green River Basin, Wyoming. See “Note 4. 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.

2. Significant Accounting Policies Update

Reclassification

Certain reclassifications have been made to the Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s coal royalties, processing fees, transportation fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item “Coal related revenues” on this year’s Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s aggregates royalties, processing fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item “Aggregates related revenues” on this year’s Consolidated Statements of Comprehensive Income. The following is reclassification reconciliation:

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Recent Accounting Pronouncements

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.

3. Recent Acquisitions

Sundance. On December 19, 2013, the Company completed the acquisition of non-operated working interests in oil and gas properties in the Williston Basin of North Dakota from Sundance Energy, Inc. for $29.4 million, following post-closing purchase price adjustments. The Partnership accounted for the transaction in accordance with the authoritative guidance 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 receipt of the final valuation report from a third-party valuation firm and the subsequent allocation, the assets acquired are included in Oil and gas interests in the accompanying Balance Sheet.

Abraxas. On August 9, 2013, the Company completed the acquisition of non-operated working interests in oil and gas properties in the Williston Basin of North Dakota and Montana from Abraxas Petroleum for $38.0 million, following post-closing purchase price adjustments. The Partnership accounted for the transaction in accordance with the authoritative guidance for business combination. During the second quarter of 2014, the Partnership finalized the determination of the fair values of the assets acquired and liabilities assumed in the acquisition, with no material adjustments. The assets acquired are included in mineral rights in the accompanying Consolidated Balance Sheets.

Abraxas and Sundance combined revenues of $21.3 million and lease operating expenses of $4.2 million for the six months ended June 30, 2014 are included in oil and gas related revenues and operating expenses in the Consolidated Statements of Comprehensive Income, respectively.

4. Equity and Other Investments

The following summarized results of operations were taken from the OCI Wyoming-prepared unaudited financial statements.

Operating results:

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For the three and six months ended June 30, 2014, the Partnership derived 10% and 11%, respectively, of its revenues and other income from its equity investment in OCI Wyoming. For the same periods of 2013, the Partnership derived 9% and 8%, respectively, of its revenues and other income from its equity investment in OCI Wyoming.

The terms of the OCI Wyoming acquisition agreement included provisions for the payment of contingent consideration to Anadarko Holding Company if OCI Wyoming achieves certain earnings results in 2013, 2014 or 2015. The Partnership projected that the contingency would be $15 million at December 31, 2013.

The Partnership’s contingent consideration consists of the following:

The current portion is included in accounts payable and accrued liabilities and the long term portion is included in other non-current liabilities.

In March 2014, Anadarko Holding Company (Anadarko) gave written notice to the Partnership that Anadarko believes the reorganization transactions that occurred at OCI Wyoming in July 2013 triggered an acceleration of the Partnership’s obligation to pay the additional contingent consideration in full and demanded immediate payment of such amount. The Partnership does not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration, and the Partnership will continue to engage in discussions with Anadarko to resolve the issue. However, if Anadarko were to prevail on such claim, the Partnership would be required to pay an amount to Anadarko in excess of the $15 million accrual described above up to the net present value of $50 million (the maximum amount of the additional contingent consideration). Any such additional amount would be considered to be additional acquisition consideration and added to Equity and other unconsolidated investments.

5. Plant and Equipment

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

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6. Mineral Rights

The Partnership’s mineral rights consist of the following:

On April 7, 2014, one of the Partnership’s lessees, James River Coal Company, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As of June 30, 2014, the net book value of the Partnership’s properties leased to James River was approximately $35 million, net of previously paid minimums. At this stage in the bankruptcy process, it is unknown whether the Partnership’s leases will be accepted or rejected in the bankruptcy process or assigned to a third party in connection with a sale. However, if the Partnership’s leases are rejected in the bankruptcy or if mining operations on the Partnership’s properties cease, the Partnership may determine that some or all of such properties are impaired. In the first six months of 2014, James River accounted for approximately 1% of total revenues and other income, and for the year ended December 31, 2013, it represented 2% of total revenues and other income. The Partnership does not expect the resolution of the bankruptcy to have a material impact on its revenues and other income. The Partnership will continue to monitor these properties for potential impairment as the bankruptcy proceedings progress.

7. Intangible Assets

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

During the second quarter of 2014, the Partnership recognized an impairment expense of $5.6 million relating to an above market contract on an aggregates property. The asset impairment expense is included in Operating costs and expenses on the Consolidated Statements of Comprehensive Income.

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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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8. Long-Term Debt

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 other 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. 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 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 $48.3 million on its senior notes during the six months ended June 30, 2014. 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 six months ended June 30, 2014 and year ended December 31, 2013 were 1.97% and 2.23%, 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. At June 30, 2014 Opco had $15 million drawn under the credit facility.

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

Term Loan Facility. During 2013, Opco issued $200 million in term debt. The weighted average interest rates for the debt outstanding under the term loan for the six months ended June 30, 2014 and the year ended December 31, 2013 were 2.25% and 2.43%, respectively. 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:

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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 non-operated working interests in oil and gas assets. The credit facility has a borrowing base of $20.0 million as of June 30, 2014 and is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. At June 30, 2014, there was $2.0 million outstanding under the credit facility. The weighted average interest rate for the debt outstanding under the credit facility for the six months ended June 30, 2014 was 1.90%.

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 June 30, 2014.

9. Fair Value

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 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 and long-term senior notes are as follows:

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The fair value of the Sugar Camp override 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 facilities and term loan are variable rate debt, their fair values approximate their carrying amounts.

10. 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 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 $0.4 million at June 30, 2014 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, including Foresight Energy, 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 (unaudited) in the Partnership’s general partner, as well as 4,917,548 common units (unaudited) at June 30, 2014. At June 30, 2014, the Partnership had accounts receivable totaling $8.9 million from Cline affiliates. In addition, the overriding royalty and the lease of the loadout facility at Sugar Camp mine are classified as contracts receivable of $50.8 million on the Partnership’s Consolidated Balance Sheets. The Partnership has received $79.6 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $8.6 million was received in the current year.

Coal related revenues from Cline affiliates were $20.4 million and $17.2 million and $38.3 million and $47.3 million, for the three and six months ended June 30, 2014 and 2013, respectively. For the six months ending June 30, 2013, the results included $8.1 million from a reserve swap and $3.5 million from minimums that expired on Foresight Energy’s Macoupin mine and were recognized as revenue.

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The Partnership entered into a lease agreement related to the rail loadout and associated facilities at Sugar Camp that has been accounted for as a direct financing lease. Total projected remaining payments under the lease at June 30, 2014 are $88.8 million with unearned income of $40.9 million. The net amount receivable under the lease as of June 30, 2014 was $47.9 million, of which $1.8 million is included in Accounts receivable – affiliates while the remaining is included in Long-term contracts receivable—affiliates.

In a separate transaction, the Partnership acquired a contractual overriding royalty interest from a Cline affiliate that will provide for payments based upon production from specific tons at the Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of June 30, 2014 was $6.2 million, of which $1.5 million is included in Accounts receivable – affiliates while the remaining is included in Long-term contracts receivable—affiliate.

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 June 30, 2014, 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 $0.1 million from Corsa at June 30, 2014.

A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. Subsequent to the end of the second quarter of 2013, Taggart was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. The Partnership owns and leases preparation plants to Forge, which operates the plants. The lease payments were based on the sales price for the coal that was processed through the facilities.

Revenues from Forge for the six months ended June 30, 2013 were $1.8 million. Subsequent to the end of the second quarter of 2013, Taggart/Forge is no longer considered a related party of the Partnership.

11. 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.

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 June 30, 2014. The Partnership is not associated with any environmental contamination that may require remediation costs.

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12. Major Lessees

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

In the first six months of 2014, the Partnership derived over 36% of its total revenues and other income from the two companies listed above. 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 10% and 11%, respectively, of the Partnership’s total revenues and other income for the first three and six months of 2014.

13. 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, 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 2014 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 0.13% to 1.28% and 30.42% to 33.33%, respectively at June 30, 2014. The Partnership’s average distribution rate of 7.34% and historical forfeiture rate of 5.22% were used in the calculation at June 30, 2014. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $1.5 million and $1.9 million for the three months ended June 30, 2014 and 2013, respectively, and for the six months ended June 30, 2014 and 2013 the Partnership recorded expense of $0.4 million and $7.0 million, respectively. In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $5.3 million and $7.0 million were made during the six month period ended June 30, 2014 and 2013, respectively.

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In connection with the phantom unit awards, 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 June 30, 2014 was $9.4 million.

14. Shelf Registration Statements and “At-the-Market” Program

On April 24, 2012, the Partnership filed an automatically effective shelf registration statement on Form S-3 with the SEC that is available for registered offerings of common units and debt securities. This shelf replaced the Partnership’s previous shelf registration statement, which expired at the end of February 2012.

On August 15, 2012, the Partnership filed a shelf registration statement on Form S-3 that registered all of the common units held by Adena Minerals. This shelf registration statement was declared effective by the SEC on September 21, 2012. Following the effectiveness of this registration statement, Adena distributed 15,181,716 common units to its shareholders, and the Partnership subsequently filed prospectus supplements to register the resale of these common units by those shareholders. The shelf registration statement filed in August 2012 also registered up to $500 million in equity securities that may be issued by the Partnership. On November 12, 2013, the Partnership filed a prospectus supplement and entered into an Equity Distribution Agreement relating to the offer and sale from time to time of common units having an aggregate offering price of $75 million through one or more managers acting as sales agents at prices to be agreed upon at the time of sale. Under the terms of the Equity Distribution Agreement, the Partnership may also sell common units from time to time to any manager as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to any manager as principal would be pursuant to the terms of a separate terms agreement between the Partnership and such manager. Sales of common units in this “at-the-market” (“ATM”) program are made pursuant to the shelf registration statement declared effective in September 2012. For the six months ended June 30, 2014 the Partnership sold 1,057,105 common units for an average price of $16.08 for gross proceeds of $17.0 million, including proceeds relating to 185,097 common units that initially traded on or prior to June 30, 2014 but that were settled subsequent to June 30, 2014. At June 30, 2014, the Partnership had received $14.0 million of the proceeds and recorded an accounts receivable for the balance of $3.0 million relating to the common units that settled subsequent to June 30, 2014. In addition, the Partnership has agreed to pay the ATM program manager a fee of up to 2% of the gross proceeds from the sale of common units under the ATM program and had accrued $0.1 million in such fees payable to the manager of the ATM program as of June 30, 2014.

On April 12, 2013, the Partnership filed a resale shelf registration statement on Form S-3 to register the 3,784,572 common units issued in the January 2013 private placement related to funding of the OCI Wyoming acquisition. This shelf registration statement was declared effective by the SEC in May 2013. A portion of the common units issued in the private placement were issued, directly and indirectly, to certain of the Partnership’s affiliates, including Corbin J. Robertson, Jr. and Christopher Cline.

15. Distributions

On May 14, 2014, the Partnership paid a quarterly distribution $0.35 per unit to all holders of common units on May 5, 2014.

16. Subsequent Events

The following represents material events that have occurred subsequent to June 30, 2014 through the time of the Partnership’s filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission:

Distributions

On July 22, 2014, the Partnership declared a distribution of $0.35 per unit to be paid on August 14, 2014 to holders of common units on August 5, 2014.

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Distributions Received From Unconsolidated Equity and Other Investments

Subsequent to June 30, 2014, the Partnership received $10.3 million in cash distributions from its equity investment in OCI Wyoming.

ATM Program

As of the date of this filing, the Partnership has issued an additional 381,009 units at an average price of $16.33 for gross proceeds of $6.2 million through its ATM program.

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Item 2. 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 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, 2013, as filed on February 28, 2014.

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 a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, oil and gas, construction aggregates, frac sand and other natural resources. For the six months ended June 30, 2014, we recognized approximately $107.7 million (63%) of our revenues and other income from coal-related sources, and $63.1 million (37%) of our revenues and other income from non-coal-related sources.

Our coal reserves are located 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, 2013, we owned or controlled approximately 2.3 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, particularly in the Illinois Basin. In addition, we own various interests in oil and gas properties that are located in the Williston Basin, the Appalachian Basin, Louisiana and Oklahoma, and we own approximately 500 million tons of aggregate reserves located in a number of states across the country.

We own a 49% interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. OCI Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business, and record the income in accordance with our 49% equity interest in the company.

In our coal and aggregates 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.

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 incur capital expenditures and operating expenses associated with the non-operated working interests in oil and gas assets. 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.

Our Current Liquidity Position

As of June 30, 2014, Opco had $285.0 million in available borrowing capacity under its revolving credit facility. As of such date, NRP Oil and Gas had $18.0 million in available borrowing capacity under its revolving credit facility. 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.

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In addition to the amounts available under our revolving credit facilities, we had $70.0 million in cash as of June 30, 2014. As of the date of this report, we have sold 1,438,114 common units through our “at-the-market” offering (“ATM”) program for approximately $23.2 million in gross proceeds, excluding our general partner’s capital contribution to maintain its 2% general partner interest in us. During the first half of 2014, we repaid $48.3 million of principal on Opco’s senior notes and repaid $5.0 million under Opco’s revolving credit facility, thereby reducing our total outstanding debt by $53.3 million. Because we used cash to repay principal on Opco’s notes during the first half of 2014, our current liabilities exceeded our current assets by approximately $7.4 million as of June 30, 2014.

We believe that the combination of our borrowing capacity under our revolving credit facilities and our cash on hand gives us enough liquidity to meet our current financial needs. Other than $81 million in principal repayments due on Opco’s senior notes each year for the next several years (including $32.5 million of principal payments remaining in 2014), we do not have any debt maturing until 2016. While we intend to reduce our leverage by repaying such amounts with cash from operations and issuances of equity through our ATM program, we may refinance such amounts as they come due.

Current Results/Market Outlook

Our total revenues and other income for the six months ended June 30, 2014 were $170.9 million, which were down compared to $181.1 million in total revenues and other income earned for the six months ended June 30, 2013. Although our total revenues and other income were down only 6% from the first half of 2013, our coal related revenues were down approximately 26% compared to the same period. The majority of the decrease in coal-related revenues was due to lower Central Appalachian coal royalty revenues, which were down 23% from the first half of 2013. We continue to see the benefits of our diversification efforts, as our revenues and other income from sources other than coal represented 37% of our total revenues and other income in the first half of 2014, up from approximately 20% of total revenues and other income in the first half of 2013. During the first half of 2014, our investment in OCI Wyoming’s trona mining and soda ash production operations contributed $19.2 million in other income, and our oil and gas revenues increased to $27.9 million, up $22.0 million as compared to the first half of 2013.

The challenges that have affected the coal markets over the last two years have continued into the first half of 2014. While the thermal coal market was starting to show signs of recovery earlier this year aided by the cold winter and higher natural gas prices, the cooler than anticipated summer so far has put downward pressure on natural gas prices and dampened some of the optimism around thermal coal prices. In addition, rail transportation service issues continue to affect thermal coal prices. We believe that thermal coal production from our properties in the low-cost Illinois Basin will continue to remain strong in spite of the weak thermal markets, and in the second quarter of 2014, we completed an acquisition of additional thermal coal reserves in the Illinois Basin for $5.0 million from a private seller. We expect the markets for thermal coal from our other regions to remain weak for the remainder of 2014.

We continue to have substantial exposure to metallurgical coal, from which we derived approximately 41% of our coal revenues and 32% of the related production during the first six months of 2014. The third quarter 2014 benchmark price for metallurgical coal remains at a multi-year low of $120 per metric ton. The global metallurgical coal market continues to suffer from oversupply in addition to reduced demand from China. In June 2014, Cliffs Natural Resources issued a WARN notice and announced that it intended to idle the Pinnacle Mine in West Virginia, where we own substantial metallurgical coal reserves. Although Cliffs announced in August 2014 that it does not intend to idle the mine, if the mine were to be idled for an extended period, it would materially reduce our metallurgical coal revenues. We have exposure to three mines included in a WARN notice issued by Alpha Natural Resources in West Virginia in July, but even if those mines are ultimately idled, we do not expect there to be a material adverse impact on our 2014 results, as the mines are projected to continue full operations through the third quarter. We do not anticipate metallurgical coal prices recovering in 2014, and additional reductions of production of metallurgical coal from our properties may occur in the remainder of 2014 as long as prices remain at current levels.

Our trona mining and soda ash refinery business performed in line with our expectations during the first six months of 2014. The international market for soda ash continues to improve, as global production capacity for high-cost synthetic soda ash continues to be reduced, and OCI Wyoming’s sales through ANSAC were better than expected. The strong international sales were partially offset by lower than expected domestic sales volumes, which are typically sold at a higher price. The cash we receive from OCI Wyoming is in part determined by the quarterly distribution declared by OCI Resources LP. Subsequent to the end of the second quarter, OCI Resources LP announced that it would maintain its quarterly distribution at $0.50 per common unit.

The natural gas and crude oil markets in the second quarter have continued to be robust. Natural gas prices displayed relative stability despite moderately cool weather and large builds in storage. Oil markets have continued a strong growth trajectory into the second quarter due to healthy prices and production growth from new wells coming on line in the primary oil producing plays such as the Bakken/Three Forks. We anticipate our oil and natural gas assets will see continued development and production growth during 2014 as long as the commodities markets remain strong.

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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. In addition, the electric utility industry, which is the most significant end-user of domestic coal, is subject to extensive regulation regarding the environmental impact of its power generation activities. In January 2014, EPA published proposed new source performance standards for greenhouse gas emissions from new fossil fuel-fired electric generating units. The effect of the proposed rules would be to require partial carbon capture and sequestration on any new coal-fired power plants, which may amount to their effective prohibition. In June 2014, EPA issued proposed regulations on existing fossil fuel-fired power plants (the Clean Power Plan), calling for a nationwide reduction in CO₂ emissions of 30% below 2005 levels by 2030. While the timing of implementation of these proposed rules is uncertain, we expect that EPA’s proposed regulations for new power plants and the Clean Power Plan will negatively affect the viability of coal-fired power generation, which will ultimately reduce coal consumption and the production of coal from our properties. Furthermore, EPA’s Mercury and Air Toxics (MATS) rule and Cross-State Air Pollution Rule (CSAPR), which have been recently upheld by U.S. federal courts, are expected to adversely affect coal-fired power plants in the nearer term. Additional recent decisions by U.S. federal courts granting EPA the power to challenge and under certain circumstances retroactively veto permits further prolongs uncertainties for companies operating with Clean Water Act fill permits and their business partners.

In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators and landowners. In 2012 and 2013, several citizen group lawsuits were filed against mine operators for allegedly violating conditions in their NPDES permits requiring compliance with West Virginia’s water quality standards. Some of the lawsuits allege violations of water quality standards for selenium, whereas others allege that discharges of conductivity and sulfate are causing violations of West Virginia’s narrative water quality standards, which generally prohibit adverse effects to aquatic life. The citizen suit groups seek penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate. While it is too early to determine the ultimate resolution of these lawsuits, any rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in large treatment expenses for our lessees. In 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. While it is too early to predict the final outcome of any of these lawsuits, any final 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.

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 December 2013, we acquired 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 $29.4 million, following post-closing purchase price adjustments. The properties, which are all held by production are located in McKenzie, Mountrail and Dunn counties and are actively being developed.

Abraxas. In August 2013, we acquired non-operated working interests in producing oil and gas properties in the Williston Basin of North Dakota and Montana, including properties producing from the Bakken/Three Forks play, from Abraxas Petroleum Corporation for $38.0 million, following post-closing purchase price adjustments.

OCI Wyoming. In January 2013, we acquired a non-controlling equity interest in OCI Wyoming, an operator of a trona ore mining operation and a soda ash refinery in the Green River Basin, Wyoming, from Anadarko Holding Company and its subsidiary, Big Island Trona Company for $292.5 million. The acquisition agreement provides for up to the net present value of $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. We accrued $15 million as part of the purchase consideration, of which we have paid $0.5 million in contingent consideration to Anadarko with respect to 2013.

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Non-GAAP Financial Measures

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, proceeds from sale of assets, returns on direct financing lease and contractual override and distributions from unconsolidated affiliates. 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.

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

EBITDA

EBITDA is a non-GAAP financial measure that we define as earnings before interest, taxes, depreciation, depletion and amortization and asset impairment. EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDA provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax positions. EBITDA does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital and other commitments and obligations. Our management team believes EBITDA is useful in evaluating our financial performance because this measure is widely used by analysts and investors for comparative purposes. EBITDA is a financial measure widely used by investors in the high-yield bond market. There are significant limitations to using EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDA reported by different companies.

Reconciliation of “Net income” to “EBITDA”

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EBITDA presented in the table above differs from the EBITDDA definitions contained in Opco’s debt agreement covenants. In calculating EBITDDA for purposes of Opco’s debt covenant compliance, pro forma effect may be given to acquisitions and dispositions made during the relevant period. See “—Liquidity and Capital Resources—Contractual Obligations and Commercial Commitments—Opco Debt” for a description of Opco’s debt agreements.

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Results of Operations

As disclosed in Note 2: “Significant Accounting Policies Update,” amounts relating to coal royalties, processing fees, transportation fees, minimums recognized as revenue, override royalties and other for the three and six months ended June 30, 2013 have been reclassified into a single line item “Coal related revenues” on the Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014. Similarly, amounts relating to 2013 aggregate royalties, processing fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item “Aggregate related revenues” on the 2014 Consolidated Statements of Comprehensive Income. Accordingly, we have revised our comparative discussions below to make corresponding changes.

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Coal Related Revenues