Natural Resource Partners Annual Report 2023

Plain-text annual report

NRPAnnual Report2023Natural Resource Partners L.P.To the Unitholders of Natural Resource Partners L.P. (“NRP”): NRP generated $313 million of free cash flow in 2023, the highest level in the history of the Partnership. As of this writing, total obligations, which include debt, 12% preferred equity, and warrants, stand at approximately $270 million. Our revolving credit facility has been upsized to $200 million, providing additional cash to accelerate the payoff of preferreds and warrants. We paid $69 million of distributions to common unitholders in 2023, more than double the payout the previous year. We have paid off nearly 90% of our debt since embarking on the de-risking strategy in 2015, redeemed 71% of the preferreds at par, and settled 92% of the warrants. We stand firm in our belief that this is the best approach to maximize the intrinsic value of our business, which should in turn maximize the long-term return on your investment. A word of caution is in order after two consecutive years of record-setting free cash flow generation. The primary drivers of recent performance were historically high prices for metallurgical coal and soda ash, which are unlikely to persist. We believe that muted investment in new supply will provide support for metallurgical coal prices, but not at the record high levels seen in recent years. In addition, soda ash prices are under pressure from a significant increase in global supply from new projects in China, Turkey, and the United States. We believe it will take several years for the market to absorb these new supplies. While we expect the Partnership’s free cash flow to decline from 2023’s record level for the reasons discussed above, our capital structure is solid and we anticipate the business will continue to generate robust levels of free cash flow. As a result, we remain on track to achieve our goal of retiring all permanent debt, redeeming all preferred equity, and eliminating all outstanding warrants. One benefit of our long-term, intrinsic value focused approach is that we attract investors who share our philosophy. The majority of our unitholders have been invested in NRP for years. We know most of them personally. Like us, they opt for the tortoise over the hare, realizing that the benefits of compounding money over long periods of time produce the greatest investment rewards. We thank all our stakeholders for their continuing confidence, trust, and support. Thank you also to our Board of Directors for its wise guidance and counsel. Corbin J. Robertson, Jr. Chairman and Chief Executive Officer Craig Nunez President and Chief Operating Officer Natural Resource Partners L.P. 2023 Annual Report Philosophy and Strategy We are honored by the trust you have placed in us with your investment in NRP. As your partner, we strive to maximize the intrinsic value of our business and treat you the way we would want to be treated if our roles were reversed. We believe that as your partner, our economic interests should be aligned with yours. Every member of your executive team has a meaningful portion of their net worth invested in NRP. Collectively, your executives and Board of Directors own 29% of our outstanding common units. Rest assured that our investment goals are closely aligned with yours. We think long-term. We do not provide quarterly guidance or concern ourselves with meeting short-term earnings expectations. Our focus is on maximizing the Partnership’s earning power over five, ten, fifteen years, and beyond. We believe this is the best approach to maximize the intrinsic value of our business, which should in turn maximize the long-term return on your investment. We believe shared values make for good partnerships. We want partners who invest in us because they share our business philosophy and focus on long-term value creation and returns. What We Own NRP owns approximately 13 million acres of mineral interests and other property rights across the United States, including 3.5 million acres of underground pore space for the sequestration of carbon dioxide (“CO2”). If combined in a single tract, our ownership would cover roughly 20,000 square miles. Our assets provide critical inputs for the manufacturing of steel, electricity, building materials, and components used in the generation of renewable energy. We also own a 49% interest in Sisecam Wyoming, LLC, one of the world’s lowest-cost producers of soda ash, an essential ingredient for the manufacturing of glass, detergents, solar panels, and batteries for electric vehicles. What We Do Not Do We do not conduct “operations” on any of our assets or directly engage in any type of industrial activity. Instead, we lease our mineral and other rights to companies that conduct operations on our properties in exchange for paying royalties and other fees to us. Operating expenses, capital costs, and other liabilities arising out of production activities are borne entirely by our lessees. In the case of our soda ash investment, operations are managed by our partner, Sisecam Chemicals Wyoming LLC. Our Strategy 2015 marked a watershed event in the history of the Partnership. Falling commodity prices and high debt levels pushed our financial capacity to the brink. We had nearly $1.5 billion of debt, representing more than two-thirds of our capital structure. Our bonds were trading at 65 cents on the dollar, and our free cash flow was negative. We could no longer rely on external sources to refinance maturing debt. In response, we embarked on a strategy to de-lever and de-risk the Partnership. Since then, through the extraordinary contributions of our employees and the support of external stakeholders, we have made significant strides to improve the Partnership’s financial position and operating performance. We aggressively cut costs, eliminated capital expenditures, and sold off underperforming assets. 81495natD1R3_Cov_Narr.indd 3 81495natD1R3_Cov_Narr.indd 3 4/12/24 4:54 PM 4/12/24 4:54 PM Natural Resource Partners L.P. 2023 Annual Report Philosophy and Strategy Continued Today, we are proud to say that the Partnership is dramatically healthier and financially stronger than it was nine years ago. We have right-sized the business from four business segments down to two, both of which now earn returns on capital well in excess of their cost of capital. Our operating and interest expenses are each more than 70% lower than they were when we began. Our free cash flow, which had been negative, exceeded $300 million in 2023, a record for the Partnership. Our debt, which had been almost $1.5 billion, declined nearly 90%, to $156 million at the end of 2023. The financial profile of today’s NRP is so remarkedly improved from that of nine years ago, that it would be hardly recognizable to anyone who had not followed the transformation. We are especially proud that these results have been achieved without the use of debt forgiveness or bankruptcy. Let it be known that NRP keeps its promises, pays its debts, and does exactly what it says it will do. We have come a long way, but there is still more work to be done. Our goal remains to retire all permanent debt, redeem all of our 12% preferred equity, and eliminate all outstanding warrants. As demonstrated by our continued ability to generate free cash flow, permanently retire obligations, and pay common unit distributions, we remain confident we have the right philosophy and strategy in place to maximize unitholder value. 81495natD1R3_Cov_Narr.indd 4 81495natD1R3_Cov_Narr.indd 4 4/12/24 4:54 PM 4/12/24 4:54 PM Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K ☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2023 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number: 001-31465 NATURAL RESOURCE PARTNERS LP (Exact name of registrant as specified in its charter) Delaware35-2164875(State or other jurisdiction ofincorporation or organization)(I.R.S. EmployerIdentification No.)1415 Louisiana Street, Suite 3325Houston, Texas 77002(Address of principal executive offices)(Zip Code)(713) 751-7507(Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registeredCommon Units representing limited partner interests NRP New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒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 thepreceding 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 90days. Yes ☒ No ☐Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growthcompany. See definition of "accelerated filer", "large accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the ExchangeAct.Large Accelerated Filer☐ Accelerated Filer☒Non-accelerated Filer☐ Smaller Reporting Company☐ Emerging Growth Company☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revisedfinancial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control overfinancial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report ☒If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect thecorrection of an error to previously issued financial statements. ☐Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any ofthe registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yes ☐ No ☒The aggregate market value of the common units held by non-affiliates of the registrant on June 30, 2023, was $474 million based on a closing price on that date of$52.74 per unit as reported on the New York Stock Exchange.Documents incorporated by reference: None. Table of Contents TABLE OF CONTENTS Cautionary Statement Regarding Forward-Looking StatementsiiRisk Factors SummaryiiPART IItems 1. and 2.Business and Properties1Item 1A.Risk Factors16Item 1B.Unresolved Staff Comments27Item 1C.Cybersecurity27Item 3.Legal Proceedings27Item 4.Mine Safety Disclosures27 PART IIItem 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities28Item 6.[RESERVED]28Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations28Item 7A.Quantitative and Qualitative Disclosures About Market Risk40Item 8.Financial Statements and Supplementary Data41Item 9.Changes In and Disagreements with Accountants on Accounting and Financial Disclosure74Item 9A.Controls and Procedures74Item 9B.Other Information76Item 9C.Disclosure Regarding Foreign Jurisdictions that Prevent Inspections76 PART IIIItem 10.Directors and Executive Officers of the Managing General Partner and Corporate Governance77Item 11.Executive Compensation81Item 12.Security Ownership of Certain Beneficial Owners and Management96Item 13.Certain Relationships and Related Transactions, and Director Independence98Item 14.Principal Accountant Fees and Services102 PART IVItem 15.Exhibits, Financial Statement Schedules104Signatures 108 iTable of Contents CAUTIONARY STATEMENTREGARDING FORWARD-LOOKING STATEMENTS Statements included in this 10-K may constitute forward-looking statements. In addition, we and our representatives may from time to time make other oral orwritten statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding: future distributionson our common and preferred units; our business strategy; our liquidity and access to capital and financing sources; our financial strategy; prices of and demand forcoal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projected production levels by our lessees; SisecamWyoming LLC’s ("Sisecam Wyoming's") trona mining and soda ash refinery operations; distributions from our soda ash joint venture; the impact of governmentalpolicies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and global and U.S.economic conditions. These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefsconcerning future events impacting us and involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actualresults 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 this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our actual financial conditionto differ. RISK FACTORS SUMMARY We are subject to a variety of risks and uncertainties, including risks related to our business, risks related to our indebtedness, risks related to our common unitsand certain general risks, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Risks that we deemmaterial are described under “Risk Factors” in Item 1A of this report. These risks include, but are not limited to, the following: Risks Related to Our Business •Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In addition, our debt agreements and ourpartnership agreement place restrictions on our ability to pay, and in some cases raise, the quarterly distribution under certain circumstances.•Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.•Global pandemics, including the COVID-19 pandemic, have in the past and may continue to adversely affect our business.•Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material adverseeffect on our business and results of operations.•Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Sisecam Wyoming’s ability to continue tomake distributions to us.•We derive a large percentage of our revenues and other income from a small number of coal lessees.•Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect on our business and results ofoperations.•Mining operations are subject to operating risks that could result in lower revenues to us.•The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changesin fuel consumption patterns by electric power generators and a corresponding decrease in coal production by our lessees and reduced coal-related revenues.•Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending andinvestment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels.•Increased attention to climate change, environmental, social and governance ("ESG") matters and conservation measures may adversely impact our business.•In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state and local laws and regulations thatmay limit production from our properties and our profitability.•If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.•We have limited approval rights with respect to the management of our Sisecam Wyoming soda ash joint venture, including with respect to cash distributions andcapital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture andthrough our ownership of certain coal transportation assets.•Sisecam Wyoming's deca stockpiles will substantially deplete by 2024, and its production rates will decline if Sisecam Wyoming does not make further investmentsor otherwise execute on one or more initiatives to prevent such decline. •Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal, soda ash and other minerals from ourproperties.•Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess ofminimum royalty payments.•A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might beidentified in a subsequent period. Table of Contents Risks Related to Our Structure •Unitholders may not be able to remove our general partner even if they wish to do so.•The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future,which could result in substantial dilution of our common unitholders’ ownership interests.•We may issue additional common units or preferred units without common unitholder approval, which would dilute a unitholder’s existing ownership interests.•Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.•Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.•Conflicts of interest could arise among our general partner and us or the unitholders.•The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of ourdebt instruments and the triggering of payment obligations under compensation arrangements.•Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business. Tax Risks to Common Unitholders •Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-leveltaxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes or we were to becomesubject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantiallyreduced.•The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes ordiffering interpretations, possibly applied on a retroactive basis.•Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.•Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders' share ofour portfolio income may be taxable to them even though they receive other losses from our activities.•We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including income and gain from the sale ofproperties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions made withrespect to their units.•If the IRS contests the U.S. federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce ourcash available for distribution to our unitholders.•If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest)resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.•Tax gain or loss on the disposition of our common units could be more or less than expected.•Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.•Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.•Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our units.•We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge thistreatment, which could adversely affect the value of the common units.•We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge thesemethodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.•We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon theownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge thistreatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.•A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed ofthose units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and mayrecognize gain or loss from the disposition.•As a result of investing in our units, our unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or ownor acquire property. General Risks •Our business is subject to cybersecurity risks. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may have an adverse effect on our business, financialcondition, results of operations, and cash flows. ivTable of Contents PART I As used in this Annual Report on Form 10-K, unless the context otherwise requires: "we," "our," "us" and the "Partnership" 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, a wholly owned subsidiary of NRP, and itssubsidiaries. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and was a co-issuer with NRP on the 9.125% senior notes due 2025 (the"2025 Senior Notes"). ITEMS 1. AND 2. BUSINESS AND PROPERTIES Partnership Structure and Management We are a publicly traded Delaware limited partnership formed in 2002. We own, manage and lease a diversified portfolio of mineral properties in the United States,including interests in coal and other natural resources and own a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), a trona ore mining andsoda ash production business. Our business is organized into two operating segments: Mineral Rights—consists of approximately 13 million acres of mineral interests and other subsurface rights across the United States. If combined in a single tract,our ownership would cover roughly 20,000 square miles. Our ownership provides critical inputs for the manufacturing of steel, electricity and basic building materials, aswell as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energyeconomy in the years to come. Soda Ash—consists of our 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining and soda ash production business located in the GreenRiver Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicalsindustries. Our operations are conducted through Opco and our operating assets are owned by our subsidiaries. NRP (GP) LP, our general partner (the "general partner" or"NRP GP"), has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its generalpartner, GP Natural Resource Partners LLC (the "managing general partner"), conducts its business and operations and the board of directors and officers of GP NaturalResource Partners LLC make decisions on our behalf. Robertson Coal Management LLC ("RCM"), a limited liability company indirectly owned by Corbin J. Robertson,Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Pursuant to the Board Representation and Observation Rights Agreement entered into in2017 with certain entities controlled by funds affiliated with Blackstone Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP(collectively referred to as "GoldenTree"), Blackstone was entitled to appoint one person to the board of directors of GP Natural Resource Partners LLC (the "Board ofDirectors"). However, in 2023, we repurchased all of Blackstone's preferred units, which were subsequently retired and no longer remain outstanding, and all rights ofBlackstone related thereto ceased as a result. In connection with the repurchase, Blackstone's board designee resigned from the Board of Directors and all members ofthe Board of Directors are now appointed by RCM. The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited Partnership or Quintana Minerals Corporation,which are companies controlled by Mr. Robertson, Jr. These officers allocate varying percentages of their time to managing our operations. Neither our general partner,GP Natural Resource Partners LLC, nor any of their affiliates receive any management fee or other compensation in connection with the management of our business, butthey are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. We have regional offices through which we conduct our operations, the largest of which is located at 5260 Irwin Road, Huntington, West Virginia 25705 and thetelephone number is (304) 522-5757. Our principal executive office is located at 1415 Louisiana Street, Suite 3325, Houston, Texas 77002 and our telephone number is(713) 751-7507. 1Table of Contents Segment and Geographic Information The amount of 2023 revenues and other income from our two operating segments is shown below. For additional business segment information, please see "Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations" and "Item 8. Financial Statements andSupplementary Data—Note 7. Segment Information" in this Annual Report on Form 10-K, which are both incorporated herein by reference. (In thousands) Amount % of TotalMineral Rights $296,612 80%Soda Ash 73,397 20%Total $370,009 100% The following map shows the approximate geographic distribution of our ownership footprint: 2Table of Contents Mineral Rights Segment Mineral Rights We do not mine, drill or produce minerals. Instead, we lease our acreage to companies engaged in the extraction of minerals in exchange for the payment ofroyalties and various other fees. The royalties we receive are generally a percentage of the gross revenue received by our lessees. The royalties we receive are typicallysupported by a floor price and minimum payment obligation that protect us during significant price or demand declines. The majority of our Mineral Rights segment revenues come from royalties related to the sale of coal from our properties. Our coal is primarily located in theAppalachia Basin, the Illinois Basin and the Northern Powder River Basin in the United States. We lease our coal to experienced mine operators under long-term leases.Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease foradditional terms. Leases include the right to renegotiate royalties and minimum payments for the additional terms. We also own and manage coal-related transportationand processing assets in the Illinois Basin that generate additional revenues generally based on throughput or rents. We also own oil and gas, industrial minerals andaggregates that generate a portion of the Mineral Rights segment revenues. Additional Mineral Rights segment revenues come from carbon neutral initiatives such thesale of carbon offset credits from our forestlands, potential sub-surface carbon dioxide sequestration in our pore space and opportunities to generate geothermal energyfrom our ownership. Under our standard royalty lease, we grant the operators the right to mine and sell our minerals in exchange for royalty payments based on the greater of apercentage of the sale price or fixed royalty per ton of minerals mined and sold. Lessees calculate royalty payments due to us and are required to report tons of mineralsmined and sold as well as the sales prices of the extracted minerals. Therefore, to a great extent, amounts reported as royalty revenues are based upon the reports of ourlessees. We periodically audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify thatthe information that our lessees have submitted to us is accurate. Our audit and inspection processes are designed to identify material variances from lease terms as wellas differences between the information reported to us and the actual results from each property. In addition to their royalty obligations, our lessees are often subject to minimum payments, which reflect amounts we are entitled to receive even if no miningactivity occurs during the period. Minimum payments are usually credited against future royalties that are earned as minerals are produced. In certain leases, the lesseeis time limited on the period available for recouping minimum payments and such time is unlimited on other leases. Because we do not operate, our royalty business does not bear ordinary operating costs and has limited direct exposure to environmental, permitting and laborrisks. Our lessees, as operators, are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. Inaddition, the lessees generally bear all labor-related risks, including retiree health care costs, black lung benefits and workers’ compensation costs associated withoperating the mines on our coal and aggregates properties. We pay property taxes on our properties, which are largely reimbursed by our lessees pursuant to the termsof the various lease agreements. The SEC amended the property disclosure requirements for registrants with significant mining activities, effective for the fiscal year 2021, with new rules which wecomply with in this Annual Report on Form 10-K. The rules contain exceptions that allow royalty companies, such as NRP, to omit information that they lack access toand cannot obtain without incurring an unreasonable burden or expense. As a royalty company, we do not have access to the information required to prepare thetechnical reports used to determine reserves under the rules, and we are not able to obtain such information without unreasonable burden or expense. The rules requirethat reserve estimates be based on and disclosures include technical reports prepared using extensive mine-specific geological and engineering data, as well as marketand cost assumptions that we as a mineral owner do not have, including, but not limited to a) site infrastructure costs; b) processing plant costs; c) detailed analysis ofenvironmental compliance and permitting requirements; d) detailed baseline studies with impact assessment; and e) detailed tailings disposal, reclamation and mitigationplans. Our leases do not require the operators of our material properties to prepare technical report summaries or permit us the access and information sufficient toprepare our own technical report summaries under the rules. As a result, we are relying on the royalty company exceptions and have ceased to report coal and otherhard mineral reserves. In addition to summary information about our overall portfolio of mineral rights, this section provides detailed information about four properties in our MineralRights segment. These properties were determined to be material to our business based on historical revenue compared to our Mineral Rights segment considered as awhole. These four properties are: 1) Alpha-CAPP (VA), 2) Oak Grove, 3) Williamson, and 4) Hillsboro. We have also included a description of other significant properties,which have had lower revenues historically than our material properties but are important to our business. Coal Metallurgical Coal Metallurgical (“Met”) coal is used to fuel blast furnaces that forge steel and is the primary driver of our long-term cash flows. Met coal is a high-quality, cleanercoal that generates exceptionally high temperatures when burned and is an essential element in the steel manufacturing process. Metallurgical coal is a finite anddeclining resource, particularly in industrialized nations. We believe the indispensable role met coal plays in manufacturing steel combined with the increasing scarcityof the resource will provide support for this portion of our business for decades to come. Our metallurgical coal is located in the Northern, Central and SouthernAppalachian regions of the United States. Thermal Coal Thermal coal, sometimes referred to as steam coal, is used in the production of electricity. The amount of thermal coal produced in the United States has beensteadily falling over the last decade as energy providers shift from coal-fired plants to natural gas-fired facilities, and to a lesser extent, alternative energy sources suchas geothermal, wind and solar. We believe the long-term secular decline experienced by thermal coal over the last decade will continue. That fact, combined with thelong-term strength of our metallurgical business and the carbon neutral initiatives we discuss below, will result in thermal coal becoming a diminishing contributor toNRP in years to come. The vast majority of our thermal sales are located in Illinois and its operations are some of the most cost-efficient mines east of the MississippiRiver. The remainder of our thermal coal is located in Montana, the Gulf Coast and Appalachia. 3Table of Contents Coal Production Information The following tables present the type of coal sales volumes by major coal region for the years ended December 31, 2023, 2022 and 2021: For the Year Ended December 31, 2023 Type of Coal (Tons in thousands) Thermal Metallurgical Total Appalachia Basin Northern 794 351 1,145 Central 1,418 12,509 13,927 Southern — 2,670 2,670 Total Appalachia Basin 2,212 15,530 17,742 Illinois Basin 8,119 — 8,119 Northern Powder River Basin 4,589 — 4,589 Gulf Coast 1,477 — 1,477 Total 16,397 15,530 31,927 For the Year Ended December 31, 2022 Type of Coal (Tons in thousands) Thermal Metallurgical Total Appalachia Basin Northern 1,166 530 1,696 Central 1,186 12,460 13,646 Southern 93 1,691 1,784 Total Appalachia Basin 2,445 14,681 17,126 Illinois Basin 11,135 — 11,135 Northern Powder River Basin 4,288 — 4,288 Gulf Coast 385 — 385 Total 18,253 14,681 32,934 For the Year Ended December 31, 2021 Type of Coal (Tons in thousands) Thermal Metallurgical Total Appalachia Basin Northern 718 617 1,335 Central 1,140 11,139 12,279 Southern 119 1,452 1,571 Total Appalachia Basin 1,977 13,208 15,185 Illinois Basin 9,388 — 9,388 Northern Powder River Basin 3,151 — 3,151 Gulf Coast 55 55 Total 14,571 13,208 27,779 Major Coal Producing Properties The following table provides a summary of our significant coal royalty properties for 2023 and is followed by additional information for each property: Region Property/Lease Name Operator(s) Coal TypeAppalachia Basin Central Alpha-CAPP (VA) Alpha Metallurgical Resources Inc. MetCentral Kepler Alpha Metallurgical Resources Inc. MetCentral Elk Creek Ramaco Royalty Company, LLC MetCentral Coal Mountain ECP MetSouthern Oak Grove Hatfield Metallurgical Coal Holdings, LLC MetIllinois Basin Williamson Foresight Energy Resources LLC ThermalIllinois Basin Hillsboro Foresight Energy Resources LLC ThermalNorthern Powder River Basin Western Energy Rosebud Mining, LLC Thermal 4Table of Contents Appalachia Basin—Central Appalachia Alpha-CAPP (VA). The Alpha-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. Substantially all of the tons soldfrom this property in 2023 were metallurgical coal. We lease this property to subsidiaries of Alpha Metallurgical Resources Inc. ("Alpha") and previously leased it tosubsidiaries of Contura Energy, Inc. The current lease with Alpha expires at the end of 2028 and will automatically renew unless otherwise notified. We receive paymentsbased on the greater of a percentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject tominimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are credited against futureroyalties that are earned as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Production comes fromunderground room and pillar and surface mines and is trucked to one of two preparation plants. Coal is shipped via the CSX and Norfolk Southern railroads to domesticand export metallurgical customers. The book value of this property was $46.3 million at December 31, 2023. Below is a map of our Alpha-CAPP (VA) property: Elk Creek. The Elk Creek property is located in Logan and Wyoming Counties, West Virginia. We lease this property to Ramaco Resources, Inc. Metallurgicalcoal is produced from surface and underground mines and is transported by belt and truck to a preparation plant on the property. Coal is shipped via the CSX railroad toboth domestic and export metallurgical customers. Coal Mountain. The Coal Mountain property is located in Wyoming County, West Virginia. We lease this property to ECP. Metallurgical coal is produced from amulti-seam surface mine and coal is transported by truck to a preparation plant on the property. Coal is shipped via the Norfolk Southern railroad to both domestic andexport metallurgical customers. Kepler. The Kepler property is located in Wyoming County, West Virginia. Substantially all of the coal sold from this property in 2023 was metallurgical coal. Welease this property to a subsidiary of Alpha. Coal is produced from underground mines and transported by belt or truck to the preparation plant on the property. Coal isshipped via the Norfolk Southern railroad to export metallurgical customers. 5Table of Contents Appalachia Basin—Southern Appalachia Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. We currently lease this property to a subsidiary of Hatfield Metallurgical CoalHoldings, LLC ("Hatfield Metallurgical"). Previous operators of this property were Murray Metallurgical Coal Holdings LLC, Mission Coal, LLC, and Seneca Resources,LLC. The current lease with Hatfield Metallurgical expires in 2024 and will automatically renew unless otherwise notified. We receive payments based on the greater of apercentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject to minimum payments, whichreflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are credited against future royalties that are earned asminerals are produced and the lessee is time limited on the period available for recouping minimum payments. Metallurgical coal production comes from a longwall mineand is transported by beltline to a preparation plant. Metallurgical products are then shipped via railroad and barge to both domestic and export customers. The bookvalue of this property was $3.5 million at December 31, 2023. Below is a map of our Oak Grove property: 6Table of Contents Illinois Basin Williamson. The Williamson property is located in Franklin and Williamson Counties, Illinois. This property is under leases to Williamson Energy, a subsidiary ofForesight Energy Resources LLC ("Foresight"). The current leases expire in 2026 and 2033 and will automatically renew unless otherwise notified. We receive paymentsbased on the greater of a percentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, these leases are subject tominimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are credited against futureroyalties that are earned as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Thermal coal production comesfrom a longwall mine. Coal is shipped primarily via the Canadian National railroad to export customers. The book value of this property was $37.0 million at December 31,2023. Below is a map of our Williamson property: 7Table of Contents Hillsboro. The Hillsboro property is located in Montgomery and Bond Counties, Illinois. This property is under lease to Hillsboro Energy, a subsidiary ofForesight. The current lease expires in 2033 and will automatically renew unless otherwise notified. We receive payments based on the greater of a percentage of the saleprice or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject to non-recoupable minimum payments, which reflectamounts we are entitled to receive even if no mining activity occurs during the period. Thermal coal production comes from a longwall mine. Coal is shipped by rail viaeither the Union Pacific, Norfolk Southern or Canadian National railroads, or by barges to domestic utilities customers. The book value of this property was $209.3million at December 31, 2023. Below is a map of our Hillsboro property: In addition to these properties, we own loadout and other transportation assets at the Williamson mine and at the Macoupin and Sugar Camp mines, which are alsooperated by Foresight. See "—Coal Transportation and Processing Assets" below for additional information on these assets. Production at the Foresight Macoupin mine was temporarily ceased in March 2020. Foresight is no longer obligated to make royalty, transportation fee, orquarterly minimum payments to us under the Macoupin coal mining lease and transportation agreements. Foresight will instead pay an annual Macoupin fee of $2.0million to NRP each year through 2026. Foresight also forfeited its right to recoup all previously paid but unrecouped minimum payments with respect to the Macoupinmine. At all times that the Macoupin mine remains in temporary cessation of production, Foresight will take reasonable actions to preserve, protect, and store theequipment, infrastructure, and property located at the mine. Beginning January 1, 2027, we may at any time elect to cause Foresight to transfer the Macoupin mine and all associated equipment and permits to us for noconsideration. If we make this election, we will assume all liabilities associated with the Macoupin mine. Also beginning January 1, 2027, Foresight may at any time electto offer to sell the Macoupin assets to us for $1.00. If we accept Foresight’s offer, we will assume all liabilities associated with the Macoupin mine. If we do not acceptForesight’s offer, Foresight may proceed to permanently seal the Macoupin mine and conduct all reclamation activities. To the extent the elections described above arenot made, Foresight will continue to pay the annual $2.0 million fee to NRP each year that the mine remains in temporary cessation of production. In addition, Foresightmay determine at any time to recommence operations at the Macoupin mine, at which time we and Foresight will negotiate in good faith to enter into new coal mininglease and transportation agreements applicable to the Macoupin mine. 8Table of Contents Northern Powder River Basin Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. We lease this property to a subsidiary of RosebudMining, LLC. Thermal coal is produced by surface dragline mining methods. Coal is transported by either truck or beltline to the Colstrip generation station located atthe mine mouth. Coal Transportation and Processing Assets We own transportation and processing infrastructure related to certain of our coal properties, including loadout and other transportation assets at Foresight'sWilliamson mine in the Illinois Basin, for which we collect throughput fees or rents. We lease our Williamson transportation and processing infrastructure to a subsidiaryof Foresight and are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we subcontract to a subsidiary ofForesight. In addition, we own rail loadout and associated infrastructure at the Sugar Camp mine, an Illinois Basin mine also operated by a subsidiary of Foresight.While we own coal at the Williamson mine, we do not own coal at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresightand we collect minimums and throughput fees. We recorded $14.9 million in revenue related to our coal transportation and processing assets during the year endedDecember 31, 2023. We also own transportation and processing infrastructure, including loadout and other transportation assets at Foresight's Macoupin mine. As previouslymentioned, the Macoupin mine was temporarily ceased in March 2020 and Foresight is no longer obligated to make transportation fee payments to us under thetransportation agreements. Oil and Gas / Industrial Minerals / Construction Aggregates Our oil and gas properties are predominately located in Louisiana and during 2023, we received $7.4 million in oil and gas royalty revenues. Our various industrialmineral and construction aggregates properties are located across the United States and include minerals such as limestone, frac sand, copper, lead and zinc. We lease aportion of these minerals to third parties in exchange for royalty payments. The structure of these leases is similar to our coal leases, and these leases typically requireminimum rental payments in addition to royalties. During 2023, we received $2.9 million in aggregates royalty revenues, including overriding royalty revenues. Carbon Neutral Initiatives We continue to explore and identify alternative carbon neutral revenue sources across our large portfolio of surface, mineral, and timber assets, including thepermanent sequestration of carbon dioxide ("CO2") underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy, aswell as lithium production. As with our existing mineral activities, we do not plan to develop or operate carbon sequestration or carbon neutral energy projects ourselvesbut we plan to lease our acreage to companies that will conduct those operations in exchange for payment of royalties and other fees to us. While the timing andlikelihood of additional cash flows being realized from these activities is uncertain, we believe our large ownership footprint throughout the United States providesadditional opportunities to create value in this regard and position us as a key beneficiary of the transitional energy economy with minimal capital investment. We executed our first carbon neutral project in the fourth quarter of 2021 through the sale of 1.1 million carbon offset credits for $13.8 million. The offset creditswere issued to us by the California Air Resources Board under its cap-and-trade program and represent 1.1 million metric tons of carbon sequestered in approximately39,000 acres of our forestland in West Virginia. We have the ability to harvest and sell future timber growth and in 2023, we sold carbon offest credits related to 2022growth for $0.6 million. Carbon Sequestration. We own approximately 3.5 million acres of specifically reserved subsurface rights in the southern United States with the potential forpermanent sequestration of greenhouse gases. The carbon capture utilization and storage industry (“CCUS”) is in its infancy and the future is highly uncertain, but afew facts are clear. A sequestration project requires acreage possessing unique geologic characteristics, close proximity to sources of industrial-scale greenhouse gasemissions or direct air capture capability, and the appropriate form of legal title that grants the acreage owner the right to sequester emissions in the subsurface. Whilecarbon sequestration rights and ownership continue to evolve, we believe we own one of the largest inventory of acreage with potential for carbon sequestrationactivities in the United States. In the first quarter of 2022 we executed our first subsurface CO2 sequestration lease on 75,000 acres of underground pore space we own in southwest Alabamawith the potential to store over 300 million metric tons of CO2. In October of 2022, we announced our second subsurface CO2 transaction with the execution of a leasefor approximately 65,000 acres of pore space we control near southeast Texas with estimated storage capacity of at least 500 million metric tons of CO2. In total, we haveapproximately 140,000 acres of pore space under lease for carbon sequestration with estimated CO2 storage capacity of 800 million metric tons. Renewable Energy. In addition, we believe portions of our asset base across the United States possess the geologic characteristics and geographical locationsnecessary for geothermal, solar and wind energy development. With regards to geothermal, the technology to generate safe and reliable “green” electricity using heatfound deep underground is advancing rapidly. Once limited to the geologic “hot spots,” new technology has made geothermal energy projects feasible in many placespreviously thought impossible. Our geothermal opportunities are predominately located in the South, Midwest and Northwest parts of the United States. In the thirdquarter of 2022 we executed our first geothermal lease with the potential to generate up to 15 megawatts of electricity. With regards to wind and solar energyopportunities, we are actively engaged in discussions for potential use of our acreage for these types of renewable energy developments predominantly in Kentuckyand West Virginia. In the first quarter of 2023 we executed a new solar lease. 9Table of Contents Soda Ash Segment We own a 49% non-controlling equity interest in Sisecam Wyoming. Prior to 2023, Sisecam Resources LP owned 51% interest in Sisecam Wyoming. SisecamResources LP was a publicly traded master limited partnership that depended on distributions from Sisecam Wyoming in order to make distributions to its publicunitholders. In 2023, Sisecam Resources LP was dissolved and Sisecam Chemicals Wyoming LLC ("SCW LLC") became the direct owner of 51% of Sisecam Wyoming.SCW LLC, our operating partner, controls and operates Sisecam Wyoming. SCW LLC is 100% owned by Sisecam Chemicals Resources LLC ("Sisecam Chemicals,")which is 60% owned by Sisecam USA Inc. ("Sisecam USA") and 40% owned by Ciner Enterprises Inc. ("Ciner Enterprises"). Sisecam USA is a direct wholly-ownedsubsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş, a Turkish Corporation ("Şişecam Parent"), which is an approximately 51%-owned subsidiary of Turkiye Is BankasiTurkiye Is Bankasi ("Isbank"). Şişecam Parent is a global company operating in soda ash, chromium chemicals, flat glass, auto glass, glassware glass packaging andglass fiber sectors. Şişecam Parent was founded over 88 years ago, is based in Turkey and is one of the largest industrial publicly-listed companies on the Istanbulexchange. With production facilities in several continents and in several countries, Sisecam is one of the largest glass and chemicals producers in the world. CinerEnterprises is a direct wholly-owned subsidiary of WE Soda Ltd., a U.K. Corporation (“WE Soda”). WE Soda is a direct wholly-owned subsidiary of KEW Soda Ltd., aU.K. corporation (“KEW Soda”), which is a direct wholly owned subsidiary of Akkan Enerji ve Madencilik Anonim Şirketi (“Akkan”). Akkan is directly and whollyowned by Turgay Ciner, the Chairman of the Ciner Group (“Ciner Group”), a Turkish conglomerate of companies engaged in energy and mining (including soda ashmining), media and shipping markets. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass andchemicals industries. As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine orsoda ash production plant. We appoint three of the seven members of the Board of Managers of Sisecam Wyoming and have certain limited negative controls relating tothe company. We have limited approval rights with respect to Sisecam Wyoming, and our partner controls most business decisions, including decisions with respect todistributions and capital expenditures. Sisecam Wyoming is one of the largest and lowest cost producers of soda ash in the world, serving a global market from its facility located in the Green River Basinof Wyoming. The Green River Basin geological formation holds the largest, and one of the highest purity, known deposits of trona ore in the world. Trona, a naturallyoccurring soft mineral, is also known as sodium sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. SisecamWyoming processes trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other consumer andindustrial products. The vast majority of the world’s accessible trona is located in the Green River Basin. According to historical production statistics, approximately30% of global soda ash is produced by processing trona, with the remainder being produced synthetically through chemical processes. The costs associated withprocuring the materials needed for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-basedproduction consumes less energy and produces fewer undesirable by-products than synthetic production. Sisecam Wyoming’s Green River Basin surface operations consist of leased and licensed subsurface mining areas in Wyoming. The facility is accessible by bothroad and rail. Sisecam Wyoming uses large continuous mining machines and underground shuttle cars in its mining operations. Its processing assets consist primarilyof material sizing units, conveyors, calciners, dissolver circuits, thickener tanks, drum filters, evaporators and rotary dryers. In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering liquor, a solution consisting of sodium carbonatedissolved in water. Sisecam Wyoming then adds activated carbon to filters to remove organic impurities, which can cause color contamination in the final product. Theresulting clear liquid is then crystallized in evaporators, producing sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge toremove excess water. The resulting material is dried in a product dryer to form anhydrous sodium carbonate, or soda ash. The resulting processed soda ash is thenstored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. The facility is in good working condition and has been in servicefor more than 60 years. Deca Rehydration. The evaporation stage of trona ore processing produces a precipitate and natural by-product called deca. "Deca," short for sodium carbonatedecahydrate, is one part soda ash and ten parts water. Solar evaporation causes deca to crystallize and precipitate to the bottom of the four main surface ponds at theGreen River Basin facility. The deca rehydration process enables Sisecam Wyoming to recover soda ash from the deca-rich purged liquor as a by-product of the refiningprocess. The soda ash contained in deca is captured by allowing the deca crystals to evaporate in the sun and separating the dehydrated crystals from the soda ash.The separated deca crystals are then blended with partially processed trona ore in the dissolving stage of the production process. This process enables SisecamWyoming to reduce waste storage needs and convert what is typically a waste product into a usable raw material. Sisecam Wyoming anticipates that its current decastockpiles will be exhausted by 2024 and that production rates will decline if that production capacity is not replaced. Shipping and Logistics. For the year ended December 31, 2023, Sisecam Wyoming assisted the majority of its domestic customers in arranging their freightservices. All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended December 31, 2023, Sisecam Wyoming shippedover 90% of its soda ash to its customers initially via a single rail line owned and controlled by Union Pacific Railroad Company ("Union Pacific"). The SisecamWyoming plant receives rail service exclusively from Union Pacific. The agreement with Union Pacific expires on December 31, 2025 and there can be no assurance that itwill be renewed on terms favorable to Sisecam Wyoming or at all. If Sisecam Wyoming does not ship at least a significant portion of its soda ash production on theUnion Pacific rail line during a twelve-month period, they must pay Union Pacific a shortfall payment under the terms of its transportation agreement. During 2023,Sisecam Wyoming had no shortfall payments and does not expect to make any such payments in the future. A leased fleet of hopper cars serve as dedicated modes ofshipment to Sisecam Wyoming's domestic and international customers. For exports, soda ash is shipped on unit trains primarily out of Longview, Washington for bulkshipments. Sisecam Wyoming has contracts securing its export capacity in bulk vessels and containers vessels. From these ports, soda ash is loaded onto ships fordelivery to ports all over the world. Sisecam Wyoming ships to customers on Cost and Freight ("CFR") and Cost, Insurance, and Freight ("CIF") basis where they payfor ocean freight and charge the customer directly for these freight costs. Sisecam Wyoming has yearly and multiyear contracts for a portion of its ocean freight withvessel owners and carriers securing capacity and reducing market risk fluctuation. 10Table of Contents Customers. Sisecam Wyoming generated approximately half of its gross revenue from export sales, which consist of both customers as well as distributors whoserve as its channel partners in certain markets. For customers in North America, Sisecam Chemicals Resources typically enters into contracts on Sisecam Wyoming’sbehalf with terms ranging from one to three years. Under these contracts, customers generally agree to purchase either minimum estimated volumes of soda ash or acertain percentage of their soda ash requirements at a fixed price for a given calendar year. Although Sisecam Wyoming does not have “take or pay” arrangements withits customers, substantially all sales are made pursuant to written agreements and not through spot sales Sisecam Wyoming’s customers consist primarily of glass manufacturing companies, which account for 50% or more of the consumption of soda ash around theworld, and chemical and detergent manufacturing companies. Sisecam Chemicals has now completed three full years directly managing its international sales, marketing and logistics activities since exiting ANSAC at the endof 2020. Sisecam Chemicals took direct control of these activities to improve access to customers and gain control over placement of its sales in the internationalmarketplace. This enhanced view of the global market allows Sisecam Chemicals to better understand supply/demand fundamentals thus allowing better decision makingfor its business. Sisecam Chemicals continues to optimize its distribution network leveraging strengths of existing distribution partners while expanding as its businessrequires in certain target areas. Leases and License. Sisecam Wyoming is party to several mining leases and one license for its subsurface mining rights. Some of the leases are renewable atSisecam Wyoming’s option upon expiration. Sisecam Wyoming pays royalties to the State of Wyoming, the U.S. Bureau of Land Management and Sweetwater RoyaltiesLLC, a subsidiary of Sweetwater Trona OpCo LLC and the successor in interest to the license with the Rock Springs Royalty Company LLC, an affiliate of OccidentalPetroleum Corporation (formerly an affiliate of Anadarko Petroleum Corporation). The royalties are calculated based upon a percentage of the value of soda ash andrelated products sold at a certain stage in the mining process. These royalty payments may be subject to a minimum domestic production volume from the Green RiverBasin facility. Sisecam Wyoming is also obligated to pay annual rentals to its lessors and licensor regardless of actual sales. In addition, Sisecam Wyoming pays aproduction tax to Sweetwater County, and trona severance tax to the State of Wyoming that is calculated based on a formula that utilizes the volume of trona ore minedand the value of the soda ash produced. Sisecam Wyoming has a perpetual right to continue operating under these leases and license as long as it maintains continuousmining operations and intends to continue renewing the leases and license as has been historical practice. As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine or soda ashproduction plant. Our partner, SCW, manages the mining and plant operations. We appoint three of the seven members of the Board of Managers of Sisecam Wyomingand have certain limited negative controls relating to the company. Significant Customers We have a significant concentration of revenues from Alpha, with total revenues of $86.1 million in 2023 from several different mining operations, includingwheelage revenues and coal overriding royalty revenues. We also have a significant concentration of revenues with Foresight and its subsidiaries, with total revenuesof $60.5 million in 2023 from all of their mining operations, including transportation and processing services revenues, coal overriding royalty revenues and wheelagerevenues. For additional information on significant customers, refer to "Item 8. Financial Statements and Supplementary Data—Note 14. Major Customers." Competition We face competition from land companies, coal producers, international steel companies and private equity firms in purchasing coal and royalty producingproperties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers invarious regions of the United States for domestic sales. Lessees compete with both large and small producers nationwide on the basis of coal price at the mine, coalquality, transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are alsoaffected by demand for electricity and steel, as well as government regulations, technological developments and the availability and the cost of generating power fromalternative fuel sources, including nuclear, natural gas, wind, solar and hydroelectric power. Sisecam Wyoming's trona mining and soda ash refinery business faces competition from a number of soda ash producers in the United States, Europe and Asia,some of which have greater market share and greater financial, production and other resources than Sisecam Wyoming does. Some of Sisecam Wyoming’s competitorsare diversified global corporations that have many lines of business and some have greater capital resources and may be in a better position to withstand a long-termdeterioration in the soda ash market. Other competitors, even if smaller in size, may have greater experience and stronger relationships in their local markets. Competitivepressures could make it more difficult for Sisecam Wyoming to retain its existing customers and attract new customers, and could also intensify the negative impact offactors that decrease demand for soda ash in the markets it serves, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental orregulatory actions that directly or indirectly increase the cost or limit the use of soda ash. 11Table of Contents Title to Property We owned substantially all of our coal and aggregates mineral rights in fee as of December 31, 2023. We lease the remainder from unaffiliated third parties. SisecamWyoming leases or licenses its trona. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirmthis belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained inconnection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdenswill materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operation of our business. For most of our properties, the surface, oil and gas and mineral or coal estates are not owned by the same entities. Some of those entities are our affiliates. Statelaw and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on theintervening coal seams. We do not anticipate that the existence of the severed estates will materially impede development of the minerals on our properties. Regulation and Environmental Matters General Operations on our properties must be conducted in compliance with all applicable federal, state and local laws and regulations. These laws and regulations includematters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation andrestoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining,water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitationson land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containingpolychlorinated biphenyls ("PCBs"). Because of extensive, comprehensive and often ambiguous regulatory requirements, violations during natural resource extractionoperations are not unusual and, notwithstanding compliance efforts, we do not believe violations can be eliminated entirely. While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations, those costs have been and are expectedto continue to be significant. Our lessees in our coal and aggregates royalty businesses are required to post performance bonds pursuant to federal and state mininglaws and regulations for the estimated costs of reclamation and mine closures, including the cost of treating mine water discharge when necessary. In many states ourlessees also pay taxes into reclamation funds that states use to achieve reclamation where site specific performance bonds are inadequate to do so. Determinations byfederal or state agencies that site specific bonds or state reclamation funds are inadequate could result in increased bonding costs for our lessees or even a cessation ofoperations if adequate levels of bonding cannot be maintained. We do not accrue for reclamation costs because our lessees are both contractually liable and liable underthe permits they hold for all costs relating to their mining operations, including the costs of reclamation and mine closures. Although the lessees typically accrueadequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. In recent years,compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers. In addition, the electric utility industry, which is the most significant end-user of thermal coal, is subject to extensive regulation regarding the environmental impactof its power generation activities, which has affected and is expected to continue to affect demand for coal mined from our properties. Current and future proposedlegislation and regulations could be adopted that will have a significant additional impact on the mining operations of our lessees or their customers’ ability to use coaland may require our lessees or their customers to change operations significantly or incur additional substantial costs that would negatively impact the coal industry. Many of the statutes discussed below also apply to Sisecam Wyoming’s trona mining and soda ash production operations, and therefore we do not present aseparate discussion of statutes related to those activities, except where appropriate. Air Emissions The Clean Air Act and corresponding state and local laws and regulations affect all aspects of our business. The Clean Air Act directly impacts our lessees’ coalmining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources thatemit various hazardous and non-hazardous air pollutants. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions ofcoal-fired electric power generating plants. There have been a series of federal rulemakings that are focused on emissions from coal-fired electric generating facilities,including the Cross-State Air Pollution Rule ("CSAPR"), regulating emissions of nitrogen oxide ("NOx") and sulfur dioxide, and the Mercury and Air Toxics Rule("MATS"), regulating emissions of hazardous air pollutants. In March 2021, the U.S. Environmental Protection Agency ("EPA") revised the CSAPR to require additionalemissions reductions of NOx from power plants in twelve states. Further, in April 2022, EPA published a proposed rule to build on the CSAPR by imposing FederalImplementation Plans on over 20 states to implement the National Ambient Air Quality Standards ("NAAQS") for ozone. However, on August 21, 2023, the EPAannounced a new review of the ozone NAAQS in combination with its reconsideration of EPA's December 2020 decision to retain the 2015 NAAQS. The EPA is expectedto release its Integrated Review Plan in the fall of 2024. Installation of additional emissions control technologies and other measures required under EPA regulationsmake it more costly to operate coal-fired power plants and could make coal a less attractive or even effectively prohibited fuel source in the planning, building andoperation of power plants in the future. These rules and regulations have resulted in a reduction in coal’s share of power generating capacity, which has negativelyimpacted our lessees’ ability to sell coal and our coal-related revenues. Further reductions in coal’s share of power generating capacity as a result of compliance withexisting or proposed rules and regulations would have a material adverse effect on our coal-related revenues. The EPA’s regulation of methane under the Clean Air Act may also affect oil and gas production on properties in which we hold oil and gas interests. In December2023, the EPA issued its methane rules, known as OOOOb and OOOOc, that establish new source and first-time existing source standards of performance for GHG andVOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission andstorage facilities. We are unable to predict at this time the impact of these requirements on any such oil and gas production on our properties. 12Table of Contents Carbon Dioxide and Greenhouse Gas ("GHG") Emissions In December 2009, EPA determined that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and welfare becauseemissions of such gases are, according to EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on its findings, EPA beganadopting and implementing regulations to restrict emissions of GHGs under various provisions of the Clean Air Act. In August 2015, EPA published its final Clean Power Plan ("CPP") Rule, a multi-factor plan designed to cut carbon pollution from existing power plants, includingcoal-fired power plants. The rule required improving the heat rate of existing coal-fired power plants and substituting lower carbon-emission sources like natural gas andrenewables in place of coal. As promulgated, the rule would force many existing coal-fired power plants to incur substantial costs in order to comply or alternativelyresult in the closure of some of these plants, likely resulting in a material adverse effect on the demand for coal by electric power generators. The rule was beingchallenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit. In February 2016, theSupreme Court of the United States stayed the CPP Rule pending a decision by the District of Columbia Circuit as well as any subsequent review by the Supreme Court.In April 2017, the United States Court of Appeals for the District of Columbia Circuit granted EPA’s motion to hold the litigation in abeyance. In December 2017, EPAissued a proposed rule repealing the CPP Rule and issued an Advance Notice of Proposed Rulemaking soliciting information regarding a potential replacement rule tothe CPP Rule. In August 2018, EPA formally proposed the Affordable Clean Energy ("ACE") Rule, which would replace the CPP Rule. The ACE Rule contemplates anarrower approach than the CPP Rule, focusing on efficiency improvements at existing power plants and eliminating the CPP Rule’s broader goals that envisionedswitches to non-fossil fuel energy sources and the implementation of efficiency measures on demand-side entities, which the EPA now considers beyond the reach of itsauthority under the Clean Air Act. The ACE Rule would also omit specific numerical emissions targets that had been established under the CPP Rule. The ACE Rulewent into effect on September 6, 2019. As a result, the United States Court of Appeals for the District of Columbia Circuit dismissed the pending challenges to the CPPRule as moot. The ACE Rule was challenged by public health groups, environmental groups, states, municipalities, industry groups, and power providers. The legalchallenges were consolidated as American Lung Assoc. v. EPA before the D.C. Circuit Court of Appeals. Dozens of parties and over 170 amici filed briefs on the merits,and oral argument was held before a three-judge panel in October 2020. In January 2021, the D.C. Circuit issued a written opinion holding that the ACE Rule was basedon EPA’s “erroneous legal premise” that when it determines the “best system of emission reduction” for existing sources, the Clean Air Act mandates that EPA may onlyconsider emission reduction measures that can be applied at and/or to a stationary source (often referred to as “inside-the-fence” measures). The Court vacated the rule,essentially reimplementing the CPP and leaving EPA to decide whether to stick with the CPP or to pursue a new rulemaking. In June 2022, the Supreme Court issued awritten opinion, West Virginia v. EPA, in which the Court invalidated the CPP because EPA lacked the authority to promulgate such an expansive rule under the “MajorQuestions Doctrine.” It is unclear whether the Biden administration will issue a replacement of the CPP. In October 2015, EPA published its final rule on performance standards for greenhouse gas emissions from new, modified, and reconstructed electric generatingunits. The final rule requires new steam generating units to use highly efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture andstorage technology. The final emission standard is less stringent than EPA had originally proposed due to updated cost assumptions, but could still have a materialadverse effect on new coal-fired power plants. The final rule has been challenged by several states, industry participants and other parties in the United States Court ofAppeals for the District of Columbia Circuit, but is not subject to a stay. In April 2017, the court granted EPA’s motion to hold the litigation in abeyance while EPAreviews the rule. In December 2018, EPA issued a proposed rule revising the best system of emission reduction (“BSER”) for newly constructed coal-fired electricgenerating units, among other changes, to replace the 2015 rule. In a status report filed with the Court on January 15, 2021, EPA requested that the case remain inabeyance until after the transition to the Biden administration. On March 17, 2021, in line with President Biden’s Executive Order 13990, EPA asked the D.C. Circuit tovacate and remand the “significant contribution” final rule. On April 5, 2021, the D.C. Circuit vacated and remanded the January 2021 final rule. Although the EPA hasnot taken further action on the December 2018 proposed rule, on May 23, 2023, the EPA issued a proposed rule setting proposed new source performance standards forgreenhouse gas emissions from new, modified, and reconstructed fossil fuel-fired electric generating units; emission guidelines for greenhouse gas emissions fromexisting fossil fuel-fired electric generating units; and repeal of the ACE Rule. The final rule is expected in 2024. Certain authorizations required for certain mining and oil and gas operations may be difficult to obtain or use due to challenges from environmental advocacygroups to the environmental analyses conducted by federal agencies before granting permits. In particular, those approvals necessary for certain coal activities that aresubject to the requirements of the National Environmental Policy Act (“NEPA”) are subject to real uncertainty. In April 2022, the Council on Environmental Quality(“CEQ”) issued a final rule, which is considered “Phase I” of the Biden Administration’s two-phased approach to modifying the NEPA, revoking some of themodifications made to the NEPA regulations under the previous administration and reincorporating the consideration of direct, indirect, and cumulative effects of majorfederal actions, including GHG emissions. In July 2023, the CEQ announced a “Phase 2” Notice of Proposed Rulemaking, the “Bipartisan Permitting ReformImplementation Rule,” which revises the implementing regulations of the procedural provisions of NEPA and implements the amendments to NEPA included in the June3, 2023, Fiscal Responsibility Act of 2023. The final rule is expected in 2024. If any mining, or oil and gas operations are subject to permitting requirements that triggerNEPA, there is likely to be some uncertainty about the viability of any approvals that our lessees may obtain. In November 2014, President Obama also announced an emission reduction agreement with China’s President Xi Jinping. The United States pledged that by 2025 itwould cut climate pollution by 26% to 28% from 2005 levels. China pledged it would reach its peak carbon dioxide emissions around 2030 or earlier, and increase its non-fossil fuel share of energy to around 20% by 2030. In December 2015, the United States was one of 196 countries that participated in the Paris Climate Conference, atwhich the participants agreed to limit their emissions in order to limit global warming to 2°C above pre-industrial levels, with an aspirational goal of 1.5°C. While there isno way to estimate the impact of these climate pledges and agreements, including, most recently, the 28th session of the United Nations Conference of the Parties("COP28") in December 2023, they could ultimately have an adverse effect on the demand for coal, both nationally and internationally, if implemented. In 2019, PresidentTrump withdrew from the Paris Climate Agreement. On February 19, 2021, the United States officially rejoined the Paris Climate Agreement per President Biden’s ordersigned January 20. Additionally, at COP28, the parties signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly and equitablemanner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for reaching net zero by that date was set. 13Table of Contents Hazardous Materials and Waste The Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or the Superfund law) and analogous state laws imposeliability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered responsible for having contributed to the releaseof a “hazardous substance” into the environment. We could become liable under federal and state Superfund and waste management statutes if our lessees are unableto pay environmental cleanup costs relating to hazardous substances. In addition, we may have liability for environmental clean-up costs in connection with SisecamWyoming's soda ash businesses. Water Discharges Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water Act and analogous state laws and regulations createtwo permitting programs for mining operations. The National Pollutant Discharge Elimination System ("NPDES") program under Section 402 of the statute isadministered by the states or EPA and regulates the concentrations of pollutants in discharges of waste and storm water from a mine site. The Section 404 program isadministered by the Army Corps of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise “waters ofthe United States.” The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and may include land features not commonlyunderstood to be a stream or wetlands. The Clean Water Act and its regulations prohibit the unpermitted discharge of pollutants into such waters, including those froma spill or leak. Similarly, Section 404 also prohibits discharges of fill material and certain other activities in waters unless authorized by the issued permit. In June 2015,EPA issued a new rule defining the scope of “Waters of the United States” (WOTUS) that are subject to regulation. The 2015 WOTUS rule was challenged by a numberof states and private parties in federal district and circuit courts. In December 2017, EPA and the Corps proposed a rule to repeal the 2015 WOTUS rule and implementthe pre-2015 definition. The repeal of the 2015 WOTUS rule took effect in December 2019. In December 2018, EPA and the Corps issued a proposed rule again revisingthe definition of “Waters of the United States.” The new rule (the Navigable Waters Protection Rule) took effect in June 2020. In most of the pending legal challenges tothe 2015 WOTUS rule, the petitioners filed amended complaints to include allegations challenging the 2020 rule. In January 2023, the EPA and the Army Corps ofEngineers published a final revised definition of WOTUS founded upon a pre-2015 definition and including updates to incorporate existing Supreme Court decisions.Judicial developments further add to this uncertainty. In October 2022, the Supreme Court heard oral arguments in Sackett v. EPA regarding the scope and authority ofthe Clean Water Act and the definition of WOTUS and in May 2023, issued a ruling invalidating certain parts of the January 2023 rule. A revised WOTUS rule wasissued in September 2023. Due to the injunction in certain states, however, the implementation of the September 2023 rule currently varies by state. States issue a certificate pursuant to Clean Water Act Section 401 that is required for the Corps of Engineers to issue a Section 404 permit. In October 2021, theU.S. District Court for the Northern District of California vacated a 2020 rule revising the Section 401 certification process. The Supreme Court stayed this vacatur and, inSeptember 2023, the EPA finalized its Clean Water Act Section 401 Water Quality Certification Improvement Rule, effective as of November 27, 2023. While the full extentand impact of these actions is unclear at this time, any disruption in the ability to obtain required permits may result in increased costs and project delays. In connectionwith its review of permits, EPA has at times sought to reduce the size of fills and to impose limits on specific conductance (conductivity) and sulfate at levels that can beunachievable absent treatment at many mines. Such actions by EPA could make it more difficult or expensive to obtain or comply with such permits, which could, in turn,have an adverse effect on our coal-related revenues. In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators and landowners. Since 2012, severalcitizen group lawsuits have been filed against mine operators for allegedly violating conditions in their National Pollutant Discharge Elimination System (“NPDES”)permits requiring compliance with West Virginia’s water quality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereasothers alleged that discharges of conductivity and sulfate were causing violations of West Virginia’s narrative water quality standards, which generally prohibit adverseeffects to aquatic life. The citizen suit groups have sought penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate.The federal district court for the Southern District of West Virginia has ruled in favor of the citizen suit groups in multiple suits alleging violations of the water qualitystandard for selenium and in two suits alleging violations of water quality standards due to discharges of conductivity (one of which was upheld on appeal by theUnited States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity orsulfate could result in large treatment expenses for our lessees. In 2015, the West Virginia Legislature enacted certain changes to West Virginia’s NPDES program toexpressly prohibit the direct enforcement of water quality standards against permit holders. EPA approved those changes as a program revision effective in March 2019.This approval may prevent future citizen suits alleging violations of water quality standards. Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, fromvalley 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 beenreclaimed, and the state reclamation bond has been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed minesite could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations. Endangered Species Act The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and WildlifeService (“USFWS”) works closely with state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related andoil and gas exploration and production activities. In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the TrumpAdministration and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while establishing a process to regulate orpermit exceptions to such a prohibition. In February 2023, the USFWS published a proposed rule that revised the requirements for an incidental take permit application.A final rule is scheduled for release in 2024. Additionally, in June 2022, the USFWS and the National Marine Fisheries Service published a final rule rescinding the 2020regulatory definition of “habitat.” If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered or to redesignate aspecies from threatened to endangered, we or the operators of the properties in which we hold oil and gas or mineral interests could be subject to additional regulatoryand permitting requirements, which in turn could increase operating costs or adversely affect our revenues. 14Table of Contents Other Regulations Affecting the Mining Industry Mine Health and Safety Laws The operations of our coal lessees and Sisecam Wyoming are subject to stringent health and safety standards that have been imposed by federal legislation sincethe adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. TheMine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposescomprehensive health and safety standards on all mining operations. In addition, the Black Lung Acts require payments of benefits by all businesses conductingcurrent mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease. Mining accidents in recent years have received national attention and instigated responses at the state and national level that have resulted in increased scrutinyof current safety practices and procedures at all mining operations, particularly underground mining operations. Since 2006, heightened scrutiny has been applied to thesafe operations of both underground and surface mines. This increased level of review has resulted in an increase in the civil penalties that mine operators have beenassessed for non-compliance. Operating companies and their supervisory employees have also been subject to criminal convictions. The Mine Safety and HealthAdministration ("MSHA") has also advised mine operators that it will be more aggressive in placing mines in the Pattern of Violations program, if a mine’s rate of injuriesor significant and substantial citations exceed a certain threshold. A mine that is placed in a Pattern of Violations program will receive additional scrutiny from MSHA. Surface Mining Control and Reclamation Act of 1977 The Surface Mining Control and Reclamation Act of 1977 ("SMCRA") and similar statutes enacted and enforced by the states impose on mine operators theresponsibility of reclaiming the land and compensating the landowner for types of damages occurring as a result of mining operations. To ensure compliance with anyreclamation obligations, mine operators are required to post performance bonds. Our coal lessees are contractually obligated under the terms of our leases to complywith all federal, state and local laws, including SMCRA. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees foruse as pasture or timberland, as specified in the reclamation plan approved by the state regulatory authority. In addition, higher and better uses of the reclaimedproperty are encouraged. Mining Permits and Approvals Numerous governmental permits or approvals such as those required by SMCRA and the Clean Water Act are required for mining operations. In connection withobtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact thatany proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and maydelay commencement or continuation of mining operations. In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan forreclaiming the mined property upon the completion of mining operations. Our lessees have obtained or applied for permits to mine a majority of the coal that is currentlyplanned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional coal planned to be mined over thefollowing five years. However, given the imposition of new requirements in the permits in the form of policies and the increased oversight review that has been exercisedby EPA, there are no assurances that they will not experience difficulty and delays in obtaining mining permits in the future. In addition, EPA has used its authority tocreate significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coaloperators. Employees and Labor Relations As of December 31, 2023, affiliates of our general partner employed 55 people who directly supported our operations. None of these employees were subject to acollective bargaining agreement. Human Capital We believe all individuals are entitled to courtesy, dignity, and respect, and we support a culture of integrity and personal and professional growth. We are strongleaders within our community, and we seek to uphold a positive presence in all areas where we live and work. Website Access to Partnership Reports Our internet address is www.nrplp.com. We make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soonas reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not a partof this report. In addition, the SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information filed by us. Corporate Governance Matters Our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy and our Corporate Governance Guidelines adopted by the Board ofDirectors, as well as the charter for our Audit Committee are available on our website at www.nrplp.com. Copies of our annual report, our Code of Business Conduct andEthics, our Disclosure Controls and Procedures Policy, our Corporate Governance Guidelines and our committee charters will be made available upon written request toour principal executive office at 1415 Louisiana St., Suite 3325, Houston, Texas 77002. 15Table of Contents ITEM 1A. RISK FACTORS Risks Related to Our Business Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In addition, our debt agreements andour partnership agreement place restrictions on our ability to pay, and in some cases raise, the quarterly distribution under certain circumstances. Because distributions on the common units are dependent on the amount of cash we generate, distributions fluctuate based on our performance. The actualamount of cash that is available to be distributed each quarter depends on numerous factors, some of which are beyond our control and the control of the generalpartner. Cash distributions are dependent primarily on cash flow, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions mightbe made during periods when we record losses and might not be made during periods when we record profits. The actual amount of cash we have to distribute eachquarter is reduced by payments in respect of debt service and other contractual obligations, including distributions on the preferred units, fixed charges, maintenancecapital expenditures, and reserves for future operating or capital needs that the Board of Directors may determine are appropriate. We have significant debt serviceobligations and obligations to pay cash distributions on our preferred units. To the extent our Board of Directors deems appropriate, it may determine to decrease theamount of the quarterly distribution on our common units or suspend or eliminate the distribution on our common units altogether. In addition, because our unitholdersare required to pay income taxes on their respective shares of our taxable income, our unitholders may be required to pay taxes in excess of any future distributions wemake. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities. See "—Tax Risks to OurUnitholders—Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Our unitholders' share ofour portfolio income may be taxable to them even though they receive other losses from our activities." Our partnership agreement requires our consolidated leverage ratio to be less than 3.25x in order to make quarterly distributions on the common units in an amountin excess of $0.45 per unit. For more information on restrictions on our ability to make distributions on our common units, see "Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Liquidity and Capital Resources" and "Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net." Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2023, we and our subsidiaries had approximately $155.5 million of total indebtedness. The terms and conditions governing the indenture forOpco’s revolving credit facility and senior notes:•require us to meet certain leverage and interest coverage ratios;•require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance ouroperations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industries in which we operate;•increase our vulnerability to economic downturns and adverse developments in our business;•limit our ability to access the bank and capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures oracquisitions or to refinance existing indebtedness;•place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;•place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governingtheir indebtedness;•make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may default on our debt obligations; and•limit management’s discretion in operating our business. Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatoryand other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cashflow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations, including payment of distributions on the preferred units.If we do not have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money, or sell assets or raise equity at unattractiveprices, including higher interest rates. We are required to make substantial principal repayments each year in connection with Opco’s senior notes, with approximately$31 million due thereunder during 2024. To the extent we borrow to make some of these payments, we may not be able to refinance these amounts on terms acceptable tous, if at all. We may not be able to refinance our debt, sell assets, borrow more money or access the bank and capital markets on terms acceptable to us, if at all. Ourability to comply with the financial and other restrictive covenants in our debt agreements will be affected by the levels of cash flow from our operations and futureevents and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event ofdefault could adversely affect our business, financial condition and results of operations. 16Table of Contents Global pandemics, including the COVID-19 pandemic have in the past and may continue to adversely affect our business. The COVID-19 pandemic adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. Inaddition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities andglobal trading markets. Coal markets faced substantial challenges prior to the pandemic, and widespread increases in unemployment and decreases in electricity andsteel demand further reduced demand and prices for coal in 2020. In addition, demand for and prices of soda ash decreased in 2020, as global manufacturing slowed. OurBoard of Directors determined to suspend cash distributions to our common unitholders with respect to the first quarter of 2020 in order to preserve liquidity due touncertainties created by the pandemic. In addition, Sisecam Wyoming suspended cash distributions to its members in 2020 due to adverse effects of the pandemic onthe global and domestic soda ash markets. Both companies have resumed distributions, however there remains a risk that distributions could be suspended in the futuredue to another global pandemic. Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material adverseeffect on our business and results of operations. Coal prices continue to be volatile and prices could decline substantially from current levels. Production by some of our lessees may not be economic if pricesdecline further or remain at current levels. The prices our lessees receive for their coal depend upon factors beyond their or our control, including:•the supply of and demand for domestic and foreign coal;•domestic and foreign governmental regulations and taxes;•changes in fuel consumption patterns of electric power generators;•the price and availability of alternative fuels, especially natural gas;•global economic conditions, including the strength of the U.S. dollar relative to other currencies;•global and domestic demand for steel;•tariff rates on imports and trade disputes, particularly involving the United States and China;•the availability of, proximity to and capacity of transportation networks and facilities;•global or national health concerns, including the outbreak of pandemic or contagious disease, such as the COVID-19 pandemic;•weather conditions; and•the effect of worldwide energy conservation measures. Natural gas is the primary fuel that competes with thermal coal for power generation, and renewable energy sources continue to gain market share in powergeneration. The abundance and ready availability of cheap natural gas, together with increased governmental regulations on the power generation industry has causeda number of utilities to switch from thermal coal to natural gas and/or close coal-powered generation plants. This switching has resulted in a decline in thermal coalprices, and to the extent that natural gas prices remain low, thermal coal prices will also remain low. Reduced international demand for export thermal coal and increasedcompetition from global producers has also put downward pressure on thermal coal prices. Our lessees produce a significant amount of metallurgical coal that is used for steel production domestically and internationally. Since the amount of steel that isproduced is tied to global economic conditions, declines in those conditions could result in the decline of steel, coke and metallurgical coal production. Sincemetallurgical coal is priced higher than thermal coal, some mines on our properties may only operate profitably if all or a portion of their production is sold asmetallurgical coal. If these mines are unable to sell metallurgical coal, they may not be economically viable and may be temporarily idled or closed. Any potential futurelessee bankruptcy filings could create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our businessand results of operations. To the extent our lessees are unable to economically produce coal over the long term, the carrying value of our coal mineral rights could be adversely affected. Along-term asset generally is deemed impaired when the future expected cash flow from its use and disposition is less than its book value. For the year ended December31, 2023, we recorded impairment charges of approximately $0.6 million related to properties that we believe our current or future lessees are unable to operate profitably.Future impairment analyses could result in additional downward adjustments to the carrying value of our assets. 17Table of Contents Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Sisecam Wyoming’s ability to continue tomake distributions to its members and on our results of operations. The market price of soda ash directly affects the profitability of Sisecam Wyoming’s soda ash production operations. If the market price for soda ash declines,Sisecam Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash has been volatile, and those markets arelikely to remain volatile in the future. The prices Sisecam Wyoming receives for its soda ash depend on numerous factors beyond Sisecam Wyoming’s control, includingworldwide and regional economic and political conditions impacting supply and demand. In addition, the impact of the Sisecam Chemicals Resources' exit from ANSACand Sisecam Wyoming’s transition to the utilization of Sisecam Group’s global distribution network for some of its export operations beginning 2021 could affect pricesreceived for export sales. Glass manufacturers and other industrial customers drive most of the demand for soda ash, and these customers experience significantfluctuations in demand and production costs. Competition from increased use of glass substitutes, such as plastic and recycled glass, has had a negative effect ondemand for soda ash. Substantial or extended declines in prices for soda ash could have a material adverse effect on Sisecam Wyoming’s ability to continue to makedistributions to its members and on our results of operations. We derive a large percentage of our revenues and other income from a small number of coal lessees. Challenges in the coal mining industry have led to significant consolidation activity. We own significant interests in several of Alpha's mining operations, whichaccounted for approximately 23% of our total revenues in 2023. We also own significant interests in all of Foresight’s mining operations, which accounted forapproximately 16% of our total revenues in 2023. Certain other lessees have made acquisitions over the past few years resulting in their having an increased interest inour coal. Any interruption in these lessees’ ability to make royalty payments to us could have a disproportionate material adverse effect on our business and results ofoperations. Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect on our business and results ofoperations. While current coal prices have recovered substantially, the recent coal price environment, together with high operating costs and limited access to capital, hascaused a number of coal producers to file for protection under The U.S. Bankruptcy Code and/or idle or close mines that they cannot operate profitably. To the extentour leases are accepted or assigned in a bankruptcy process, pre-petition amounts are required to be cured in full, but we may ultimately make concessions in thefinancial terms of those leases in order for the reorganized company or new lessor to operate profitably going forward. To the extent our leases are rejected, operationson those leases will cease, and we will be unlikely to recover the full amount of our rejection damages claims. More of our lessees may file for bankruptcy in the future,which will create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our business and results ofoperations. Mining operations are subject to operating risks that could result in lower revenues to us. Our revenues are largely dependent on the level of production of minerals from our properties, and any interruptions to or increases in costs of the productionfrom our properties may reduce our revenues. The level of production and costs thereof are subject to operating conditions or events beyond our or our lessees’ controlincluding:•difficulties or delays in acquiring necessary permits or mining or surface rights;•reclamation costs and bonding costs;•changes or variations in geologic conditions, such as the thickness of the mineral deposits and the amount of rock embedded in or overlying the mineral deposit;•mining and processing equipment failures and unexpected maintenance problems;•the availability of equipment or parts and increased costs related thereto;•the availability of transportation networks and facilities and interruptions due to transportation delays;•adverse weather and natural disasters, such as heavy rains and flooding;•labor-related interruptions and trained personnel shortages; and•mine safety incidents or accidents, including hazardous conditions, roof falls, fires and explosions. While our lessees maintain insurance coverage, there is no assurance that insurance will be available or cover the costs of these risks. Many of our lessees areexperiencing rising costs related to regulatory compliance, insurance coverage, permitting and reclamation bonding, transportation, and labor. Increased costs result indecreased profitability for our lessees and reduce the competitiveness of coal as a fuel source. In addition, we and our lessees may also incur costs and liabilitiesresulting from third-party claims for damages to property or injury to persons arising from their operations. The occurrence of any of these events or conditions couldhave a material adverse effect on our business and results of operations. 18Table of Contents The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changesin fuel consumption patterns by electric power generators and a corresponding decrease in coal production by our lessees and reduced coal-related revenues. Enactment of laws and passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actionsto limit such emissions, have resulted in and could continue to result in electricity generators switching from coal to other fuel sources and in coal-fueled power plantclosures. Further, regulations regarding new coal-fueled power plants could adversely impact the global demand for coal. The potential financial impact on us of existingand future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance oncoal as a fuel source. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price andavailability of competing fuels for power plants and environmental and other governmental regulations. We expect that substantially all newly constructed power plantsin the United States will be fired by natural gas because of lower construction and compliance costs compared to coal-fired plants and because natural gas is a cleanerburning fuel. The increasingly stringent requirements of rules and regulations promulgated under the federal Clean Air Act have resulted in more electric powergenerators shifting from coal to natural-gas-fired power plants, or to other alternative energy sources such as solar and wind. These changes have resulted in reducedcoal consumption and the production of coal from our properties and are expected to continue to have an adverse effect on our coal-related revenues. In addition to EPA’s greenhouse gas initiatives, there are several other federal rulemakings that are focused on emissions from coal-fired electric generatingfacilities, including the Cross-State Air Pollution Rule ("CSAPR") as revised in 2021, regulating emissions of nitrogen oxide and sulfur dioxide, and the Mercury and AirToxics Rule ("MATS"), regulating emissions of hazardous air pollutants. Installation of additional emissions control technologies and other measures required underthese and other EPA regulations have made it more costly to operate many coal-fired power plants and have resulted in and are expected to continue to result in plantclosures. Further reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed rules and regulations would have a materialadverse effect on our coal-related revenues. For more information on regulation of greenhouse gas and other air pollutant emissions, see "Items 1. and 2. Business andProperties—Regulation and Environmental Matters.” Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending andinvestment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels. Global climate issues continue to attract public and scientific attention. Numerous reports have engendered concern about the impacts of human activity, especiallyfossil fuel combustion, on global climate issues. In addition to government regulation of greenhouse gas and other air pollutant emissions, there have also been effortsin recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups,promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels, such as coal. Oneexample is the Net Zero Banking Alliance, a group of over 100 banks worldwide representing over 40% of global banking assets who are committed to aligning theirinvestment portfolios with net zero emissions by 2050. Further, in October 2023, the Federal Reserve, Office of the Comptroller of the Currency and the Federal DepositInsurance Corp. released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risksassociated with climate change. The impact of such efforts may adversely affect our ability to raise capital. In addition, a number of insurance companies have takenaction to limit coverage for companies in the coal industry, which could result in significant increases in our costs of insurance or in our inability to maintain insurancecoverage at current levels. Increased attention to climate change, environmental, social and governance ("ESG") matters and conservation measures may adversely impact our business. Increasing attention to climate change, societal expectations on companies to address climate change, and investor and societal expectations regarding ESG mattersand disclosures, may result in increased costs, reduced profits, increased investigations and litigation, and negative impacts on our access to capital. The SEC has alsoannounced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement. Any laws or regulations imposingmore stringent requirements on our business related to the disclosure of climate related risks may increase compliance costs, and result in potential restrictions onaccess to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions. The possible promulgation later this year by theSEC of additional reporting requirements for registrants regarding climate risks, targets and metrics may add to the cost of preparing filings and could result in additionaldisclosures that may further restrict our access to capital. Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies ontheir approach to ESG matters, and many of these ratings processes are inconsistent with each other. Such ratings are used by some investors to inform their investmentand voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increasednegative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock priceand our access to and costs of capital. Furthermore, if our competitors’ ESG performance is perceived to be greater than ours, potential or current investors may elect toinvest in our competitors instead. In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state and local laws and regulations thatmay limit production from our properties and our profitability. The operations of our lessees and Sisecam Wyoming are subject to stringent health and safety standards under increasingly strict federal, state and localenvironmental, health and safety laws, including mine safety regulations and governmental enforcement policies. Failure to comply with these laws and regulations mayresult in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limitor cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our properties. New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements,could further regulate or tax mining industries and may also require significant changes to operations, the incurrence of increased costs or the requirement to obtain newor different permits, any of which could decrease our revenues and have a material adverse effect on our financial condition or results of operations. Under SMCRA, ourcoal lessees have substantial reclamation obligations on properties where mining operations have been completed and are required to post performance bonds for theirreclamation obligations. To the extent an operator is unable to satisfy its reclamation obligations or the performance bonds posted are not sufficient to cover thoseobligations, regulatory authorities or citizens groups could attempt to shift reclamation liability onto the ultimate landowner, which if successful, could have a materialadverse effect on our financial condition. In addition to governmental regulation, private citizens’ groups have continued to be active in bringing lawsuits against coal mine operators and land owners thatallege violations of water quality standards resulting from ongoing discharges of pollutants from reclaimed mining operations, including selenium and conductivity. Anydetermination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability forcompleted and reclaimed coal mine operations and could result in substantial compliance costs or fines. For more information on regulation of greenhouse gas and otherair pollutant emissions, see "Items 1. and 2. Business and Properties—Regulation and Environmental Matters.” 19Table of Contents If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease. We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operationswithin the constraints of their leases, including decisions relating to:•the payment of minimum royalties;•marketing of the minerals mined;•mine plans, including the amount to be mined and the method and timing of mining activities;•processing and blending minerals;•expansion plans and capital expenditures;•credit risk of their customers;•permitting;•insurance and surety bonding;•acquisition of surface rights and other mineral estates;•employee wages;•transportation arrangements;•compliance with applicable laws, including environmental laws; and•mine closure and reclamation. A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us the right to terminate the lease, repossessthe property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able tofind a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existinglessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If weenter into a new lease, the replacement operator might not achieve the same levels of production or sell minerals at the same price as the lessee it replaced. In addition, itmay be difficult for us to secure new or replacement lessees. We have limited approval rights with respect to the management of our Sisecam Wyoming soda ash joint venture, including with respect to cash distributions andcapital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture andthrough our ownership of certain coal transportation assets. We do not have control over the operations of Sisecam Wyoming. We have limited approval rights with respect to Sisecam Wyoming, and our partner controlsmost business decisions, including decisions with respect to distributions and capital expenditures. During 2020, Sisecam Wyoming suspended cash distributions to itsmembers due to adverse developments in the soda ash market resulting from the COVID-19 pandemic. Distributions resumed in 2021 but no assurance can be made thatadditional suspensions will not occur in the future. In December 2021, the parent of the 51% owner of Sisecam Wyoming sold 60% of its interest to Sisecam ChemicalsUSA Inc., a wholly owned subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş. As a result of the transaction, we will continue to appoint three of the seven Board ofManagers of Sisecam Wyoming, Sisecam USA will appoint three and Ciner Enterprises Inc. will appoint one. Any changes to the distribution policy or the capitalexpenditure plans approved by the newly constituted Board of Managers could adversely affect the future cash flows to NRP and the financial condition and results ofoperations of Sisecam Wyoming. In addition, we are ultimately responsible for operating the transportation infrastructure at Foresight’s Williamson mine, and have assumed the capital andoperating risks associated with that business. As a result of these investments, we could experience increased costs as well as increased liability exposure associatedwith operating these facilities. Sisecam Wyoming’s deca stockpiles will substantially deplete by 2024 and its production rates will decline if Sisecam Wyoming does not make further investmentsor otherwise execute on one or more initiatives to prevent such decline. In 2024, Sisecam Wyoming’s deca stockpiles will be substantially depleted and Sisecam Wyoming's production rates will decline, which would impact SisecamWyoming's profitability. While Sisecam Wyoming is currently evaluating whether and when to pursue one or more initiatives that could offset this decline as well asprovide additional soda ash production above current rates, there is no guarantee that any such initiatives or investments will be executed successfully, in a timelymanner, or if at all to enable Sisecam Wyoming to maintain its current rates of production. 20Table of Contents Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal, soda ash and other minerals from ourproperties. Transportation costs represent a significant portion of the total delivered cost for the customers of our lessees. Increases in transportation costs could make coal aless competitive source of energy or could make minerals produced by some or all of our lessees less competitive than coal produced from other sources. On the otherhand, significant decreases in transportation costs could result in increased competition for our lessees from producers in other parts of the country. Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and/or other events could temporarily impair the ability of our lessees to supply coal to theircustomers and/or increase their costs. Many of our lessees are currently experiencing transportation-related issues due in particular to decreased availability andreliability of rail services and port congestion. Our lessees’ transportation providers may face difficulties in the future that would impair the ability of our lessees tosupply minerals to their customers, resulting in decreased royalty revenues to us. In addition, Sisecam Wyoming transports its soda ash by rail or truck and ocean vessel. As a result, its business and financial results are sensitive to increases inrail freight, trucking and ocean vessel rates. Increases in transportation costs, including increases resulting from emission control requirements, port taxes andfluctuations in the price of fuel, could make soda ash a less competitive product for glass manufacturers when compared to glass substitutes or recycled glass, or couldmake Sisecam Wyoming’s soda ash less competitive than soda ash produced by competitors that have other means of transportation or are located closer to theircustomers. Sisecam Wyoming may be unable to pass on its freight and other transportation costs in full because market prices for soda ash are generally determined bysupply and demand forces. In addition, rail operations are subject to various risks that may result in a delay or lack of service at Sisecam Wyoming’s facility, andalternative methods of transportation are impracticable or cost prohibitive. For the year ended December 31, 2023, Sisecam Wyoming shipped over 90% of its soda ashfrom the Green River facility on a single rail line owned and controlled by Union Pacific. Any substantial interruption in or increased costs related to the transportationof Sisecam Wyoming’s soda ash or the failure to renew the rail contract on favorable terms could have a material adverse effect on our financial condition and results ofoperations. Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess ofminimum royalty payments. Mineral supply contracts generally do not require operators to satisfy their obligations to their customers with resources mined from specific locations. Severalfactors may influence a lessee’s decision to supply its customers with minerals mined from properties we do not own or lease, including the royalty rates under thelessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. In addition, lessees move on and offof our properties over the course of any given year in accordance with their mine plans. If a lessee satisfies its obligations to its customers with minerals from propertieswe do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues. A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might beidentified in a subsequent period. We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may notdiscover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscoveredreporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with ourlessees. Risks Related to Our Structure Unitholders may not be able to remove our general partner even if they wish to do so. Our managing general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights onmatters affecting our business. Unitholders have no right to elect the general partner or the Board of Directors on an annual or any other basis. Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner orotherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding common units(including common units held by our general partner and its affiliates and including common units deemed to be held by the holders of the preferred units who votealong with the common unitholders on an as-converted basis). Because of their substantial ownership in us, the removal of our general partner would be difficultwithout the consent of both our general partner and its affiliates and the holders of the preferred units. In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwisechange our management:•generally, if a person (other than the holders of preferred units) acquires 20% or more of any class of units then outstanding other than from our general partner orits affiliates, the units owned by such person cannot be voted on any matter; and•our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as otherlimitations upon the unitholders’ ability to influence the manner or direction of management. As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in thetrading price. 21Table of Contents The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future,which could result in substantial dilution of our common unitholders’ ownership interests. The preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. We are required to pay quarterly distributionson the preferred units (plus any PIK units issued in lieu of preferred units) in an amount equal to 12.0% per year prior to paying any distributions on our common units.The preferred units also rank senior to the common units in right of liquidation and will be entitled to receive a liquidation preference in any such case. The preferred units may also be converted into common units under certain circumstances. The number of common units issued in any conversion will be basedon the then-current trading price of the common units at the time of conversion. Accordingly, the lower the trading price of our common units at the time of conversion,the greater the number of common units that will be issued upon conversion of the preferred units, which would result in greater dilution to our existing commonunitholders. Dilution has the following effects on our common unitholders:•an existing unitholder’s proportionate ownership interest in NRP will decrease;•the amount of cash available for distribution on each unit may decrease;•the relative voting strength of each previously outstanding unit may be diminished; and•the market price of the common units may decline. In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the preferred will have the right to removeour general partner. We may issue additional common units or preferred units without common unitholder approval, which would dilute a unitholder’s existing ownership interests. Our general partner may cause us to issue an unlimited number of common units, without common unitholder approval (subject to applicable New York StockExchange ("NYSE") rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units (including additionalpreferred units) without common unitholder approval (subject to applicable NYSE rules). In addition, we may issue additional common units upon the exercise of theoutstanding warrants held by Blackstone. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:•an existing unitholder’s proportionate ownership interest in NRP will decrease;•the amount of cash available for distribution on each unit may decrease; and•the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline. Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price. If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which itmay assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the thencurrent market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a pricethat is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units. Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders. Prior to making any distribution on the common units, we reimburse our general partner and its affiliates, including officers and directors of the general partner, forall expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partnerhas sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be chargedreasonable fees as determined by the general partner. Conflicts of interest could arise among our general partner and us or the unitholders. These conflicts may include the following:•We do not have any employees and we rely solely on employees of affiliates of the general partner;•under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;•the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly distributions to unitholders;•the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnershipagreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we canobtain more favorable terms without limiting the general partner’s liability;•under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner mayalso enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are notnecessarily the result of arm’s-length negotiations; and•the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights toone of its affiliates or to us. In addition, GoldenTree also has certain limited consent rights. In the exercise of their applicable consent rights, conflicts of interest could arise between us andour general partner on the one hand, and GoldenTree on the other hand. 22Table of Contents The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of ourdebt instruments and the triggering of payment obligations under compensation arrangements. Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of ourunitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the managing general partner from transferring its general partnershipinterest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors and officers with itsown choices and to control their decisions and actions. In addition, a change of control would constitute an event of default under our debt agreements. During the continuance of an event of default under our debtagreements, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us and/or declare all amounts payable by usimmediately due and payable. In addition, upon a change of control, the holders of the preferred units would have the right to require us to redeem the preferred units atthe liquidation preference or convert all of their preferred units into common units. A change of control also may trigger payment obligations under variouscompensation arrangements with our officers. Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligationsthat are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent asa general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constitutedparticipation in the "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under somecircumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. Tax Risks to Our Unitholders Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-leveltaxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes or we were to becomesubject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantiallyreduced. The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for U.S. federal income taxpurposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposesunless we satisfy a "qualifying income" requirement. Based on our current operations and current Treasury Regulations, we believe we satisfy the qualifying incomerequirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifyingincome requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation asan entity. If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate andwould likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income,gains, losses, deductions or credits would flow through to our unitholders. Because tax would be imposed upon us as a corporation, our cash available for distributionto our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise andother forms of taxation. We currently own assets and conduct business in several states, many of which impose a margin or franchise tax. In the future, we may expandour operations. Imposition of a similar tax on us in a jurisdiction in which we operate or in other jurisdictions to which we may expand could substantially reduce thecash available for distribution to our unitholders. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes ordiffering interpretations, possibly applied on a retroactive basis. The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units, may be modified by administrative,legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to theexisting U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership taxtreatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and otherproposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment. Further, while unitholders ofpublicly traded partnerships are, subject to certain limitations, entitled to a deduction equal to 20% of their allocable share of a publicly traded partnership’s “qualifiedbusiness income,” this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Therecan be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in amanner that could impact our ability to qualify as a partnership in the future. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult orimpossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable topredict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in ourunits. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potentialeffect on your investment in our units. 23Table of Contents Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of futurelegislation. Changes to U.S. federal income tax laws have been proposed in a prior session of Congress that would eliminate certain key U.S. federal income tax preferencesrelating to coal exploration and development. These changes include, but are not limited to (i) repealing capital gains treatment of coal and lignite royalties,(ii) eliminating current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, and (iii) repealingthe percentage depletion allowance with respect to coal properties. If enacted, these changes would limit or eliminate certain tax deductions that are currently availablewith respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the valueof an investment in our units. Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders' share ofour portfolio income may be taxable to them even though they receive other losses from our activities. Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, our unitholdersare required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cashdistributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from themwith respect to that income. For our unitholders subject to the passive loss rules, our current operations include portfolio activities (such as our coal and mineral royalty businesses) andpassive activities (such as our soda ash business). Any passive losses we generate will only be available to offset our passive income generated in the future and willnot be available to offset (i) our portfolio income, including income related to our coal and mineral royalty businesses, (ii) a unitholder’s income from other passiveactivities or investments, including investments in other publicly traded partnerships, or (iii) a unitholder’s salary or active business income. Thus, our unitholders'share of our portfolio income may be subject to U.S. federal income tax, regardless of other losses they may receive from us. We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including income and gain from the sale ofproperties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions madewith respect to their units. We may engage in transactions to reduce our leverage and manage our liquidity that would result in income and gain to our unitholders without a correspondingcash distribution. For example, we may sell assets and use the proceeds to repay existing debt, in which case, our unitholders could be allocated taxable income and gainresulting from the sale without receiving a cash distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debtrepurchases, or modifications of our existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to ourunitholders as ordinary taxable income. Our unitholders may be allocated income and gain from these transactions, and income tax liabilities arising therefrom mayexceed any distributions we make to our unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder's individual tax position,including, for example, the availability of any suspended passive losses that may offset some portion of the allocable income. Our unitholders may, however, beallocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to theunitholder’s ultimate disposition of its units. Our unitholders are encouraged to consult their tax advisors with respect to the consequences to them. If the IRS contests the U.S. federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce ourcash available for distribution to our unitholders. We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of thepositions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our unitsand the price at which they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costswill reduce our cash available for distribution. If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties andinterest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced. If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest)resulting from such audit adjustments directly from us. To the extent possible, our general partner may elect to either pay the taxes (including any applicable penaltiesand interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited andadjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustments into account and pay any resultingtaxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election willbe practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such auditadjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to makepayments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. 24Table of Contents Tax gain or loss on the disposition of our common units could be more or less than expected. If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in thosecommon units. Distributions in excess of a common unitholder's allocable share of our net taxable income result in a decrease in the tax basis in such unitholder'scommon units. Accordingly, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income to ourcommon unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their originalcost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their common units, they may incur a taxliability in excess of the amount of cash they receive from the sale. A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income due topotential recapture items, including depletion and depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of unitsif the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case ofindividuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from ourallocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the saleof units. Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However,our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation,our adjusted taxable income is computed without regard to any business interest expense or business interest income. If our “business interest” is subject to limitationunder these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders maybe subject to limitation on their ability to deduct interest expense incurred by us. Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them. Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them.For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will beunrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or otherdisposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in ourunits. Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our units. Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade orbusiness. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade orbusiness. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sellsor otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholdingtax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of anydistribution in excess of our cumulative net income. As we do not compute our cumulative net income for such purposes due to the complexity of the calculation andlack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject tosuch 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highestapplicable effective tax rate and 10%. Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the “amount realized”by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decreaseof a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly tradedpartnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor,and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publiclytraded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholdersshould consult their tax advisors regarding the impact of these rules on an investment in our common units. We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challengethis treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation and amortization positions thatmay not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefitsavailable to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact onthe value of our common units or result in audit adjustments to our unitholders' tax returns. 25Table of Contents We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge thesemethodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units. In determining the items of income, gain, loss and deduction allocable to our unitholders, including when we issue additional units, we must determine the fairmarket value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market valueestimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge thesevaluation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to ourunitholders. It also could affect the amount of gain recognized from the sale of our common units, have a negative impact on the value of our common units or result inaudit adjustments to our unitholders’ tax returns without the benefit of additional deductions. We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownershipof our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, whichcould change the allocation of items of income, gain, loss and deduction among our unitholders. We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon theownership of our common units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, wegenerally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretionof the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow asimilar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challengeour proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed ofthose units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and mayrecognize gain or loss from the disposition. Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subjectof a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner withrespect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the periodof the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by theunitholder as to those units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognitionfrom a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit theirbrokers from borrowing their units. As a result of investing in our units, our unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate orown or acquire property. In addition to U.S. federal income taxes, our unitholders are likely subject to other taxes, including state and local taxes, unincorporated business taxes and estate,inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholdersdo not live in any of those jurisdictions. Our unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all ofthese various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business ina number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expandour business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal,state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns,the payment of such taxes, and the deductibility of any taxes paid. General Risks Our business is subject to cybersecurity risks. Our business is increasingly dependent on information and operational technologies and services. Threats to information technology systems associated withcybersecurity risks and cyber incidents or attacks continue to grow. Although we utilize various procedures and controls to mitigate our exposure to such risks,cybersecurity attacks and other cyber events are evolving, unpredictable, and sometimes difficult to detect, and could lead to unauthorized access to sensitiveinformation or render data or systems unusable. In addition, the frequency and magnitude of cyber-attacks is increasing and attackers have become more sophisticated. Cyber-attacks are similarly evolving andinclude without limitation use of malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic syntheticmedia generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in criticalsystems, unauthorized release of confidential or otherwise protected information and corruption of data. We may be unable to anticipate, detect or prevent futureattacks, particularly as the methodologies used by attackers change frequently or are not recognized until deployed. We may also be unable to investigate or remediateincidents as attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence. While we presently maintain insurance coverage to protect against cybersecurity risks, we cannot ensure that it will be sufficient to cover any particular losses wemay experience as a result of such cyber-attacks. Our implementation of various procedures and controls to monitor and mitigate security threats and to increasesecurity for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such proceduresand controls will be sufficient to prevent cyber-attacks or other incidents from occurring. If a cyber-attack was to occur, it could lead to losses of sensitive information,critical infrastructure or capabilities essential to our operations, misdirected wire transfers, an inability to settle transactions or maintain operations, disruptions inoperations, or other adverse events. If we were to experience an attack and our security measures failed, the potential consequences to our business and thecommunities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potentialliability, including regulatory enforcement, violation of privacy or securities laws and regulations, and individual or class action claims. Any cyber incident could have amaterial adverse effect on our business, financial condition and results of operations. 26Table of Contents ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 1C. CYBERSECURITY Cybersecurity Risk Management and Strategy We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our criticalsystems and information. Our overall risk management program includes a cybersecurity risk assessment process, that routinely evaluates potential impacts of cybersecurity risks on ourbusiness, including our operations, financial stability, and reputation. These assessments inform our cybersecurity risk mitigation strategies. The results are regularlyshared with management and the Audit Committee as part of their involvement in managing and overseeing cybersecurity risks. Key aspects of our cybersecurity risk management program include: •risk assessments designed to help identify material cybersecurity risks to our critical systems and information;•a security team principally responsible for managing (1) our cybersecurity risk assessment processes, (2) our security controls, and (3) our response tocybersecurity incidents;•the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security controls;•cybersecurity awareness training for our employees, incident response personnel, and management; and•a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents. We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected us, includingour operations, business strategy, results of operations, or financial condition. We face ongoing risks from certain cybersecurity threats that, if realized, are reasonablylikely to materially affect us, including our operations, business strategy, results of operations, or financial condition. See "Item 1A. Risk Factors – Our business issubject to cybersecurity risks" included elsewhere in this Annual Report on Form 10-K. Cybersecurity Governance Our Board of Directors considers cybersecurity risk as part of its risk oversight function and has delegated to its Audit Committee oversight of cybersecurity andother information technology risks. Our Audit Committee oversees management’s implementation of our cybersecurity risk management program. Our Audit Committee receives periodic reports from management on our cybersecurity risks. In addition, management updates our Audit Committee, as necessary,regarding significant cybersecurity incidents. Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity.Our Board of Directors also receives briefings from management on our cybersecurity risk management program. Board members receive presentations on cybersecuritytopics from IT leadership, which includes our Chief Sustainability and Administrative Officer ("CSAO"), or external experts as part of the Board’s continuing educationon topics that impact public companies. Our cybersecurity team, led by the CSAO, is responsible for coordinating and executing on the cybersecurity response procedures and for seeking assistance fromother Partnership stakeholders and external advisors. Our cybersecurity team includes the CSAO and IT leadership. The team has primary responsibility for our overallcybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Ourcybersecurity team includes professionals with deep cybersecurity expertise across multiple industries. Our management team stays informed about and monitor efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through variousmeans, which may include briefings from internal information technology personnel, threat intelligence and other information obtained from public or private sources,including external consultants engaged by us, and alerts and reports produced by security tools deployed in the IT environment. ITEM 3. LEGAL PROCEEDINGS We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannotbe predicted with certainty, management believes these ordinary course matters will not have a material effect on our financial position, liquidity or operations. ITEM 4. MINE SAFETY DISCLOSURES None. 27Table of Contents PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES NRP Common Units Our common units are listed and traded on the NYSE under the symbol "NRP." As of February 22, 2024, there were approximately 10,250 beneficial and registeredholders of our common units. The computation of the approximate number of unitholders is based upon a broker survey. ITEM 6. [RESERVED] ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Introduction The following discussion and analysis present management’s view of our business, financial condition and overall performance and should be read in conjunction withour consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consist of the following subjects:•Executive Overview•Results of Operations•Liquidity and Capital Resources•Inflation•Environmental Regulation•Related Party Transactions•Summary of Critical Accounting Estimates•Recent Accounting Standards As used in this Item 7, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where thecontext requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC orany of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. NRPFinance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and was a co-issuer with NRP on the 9.125% senior notes due 2025 (the "2025 SeniorNotes"). 28Table of Contents Non-GAAP Financial Measures Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) less equity earnings from unconsolidated investment, net incomeattributable to non-controlling interest and gain on reserve swap; plus total distributions from unconsolidated investment, interest expense, net, debt modificationexpense, loss on extinguishment of debt, depreciation, depletion and amortization and asset impairments. Adjusted EBITDA should not be considered an alternative to,or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure offinancial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significantlimitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our netincome (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by differentcompanies. In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnershipagreement or Consolidated EBITDDA as defined in Opco's debt agreements. See "Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net" includedelsewhere in this Annual Report on Form 10-K for a description of Opco’s debt agreements. Adjusted EBITDA is a supplemental performance measure used by ourmanagement and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance ofour assets without regard to financing methods, capital structure or historical cost basis. Distributable Cash Flow Distributable cash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidatedinvestment in excess of cumulative earnings, proceeds from asset sales and disposals, including sales of discontinued operations, and return of long-term contractreceivables, less maintenance capital expenditures. DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cashflows from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies. In addition, DCF presented below is notcalculated or presented on the same basis as distributable cash flow as defined in our partnership agreement, which is used as a metric to determine whether we are ableto increase quarterly distributions to our common unitholders. DCF is a supplemental liquidity measure used by our management and by external users of our financialstatements, such as investors, commercial banks, research analysts and others to assess our ability to make cash distributions and repay debt. Free Cash Flow Free cash flow ("FCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investmentin excess of cumulative earnings and return of long-term contract receivables, less maintenance and expansion capital expenditures and cash flow used in acquisitioncosts classified as investing or financing activities. FCF is calculated before mandatory debt repayments. FCF is not a measure of financial performance under GAAPand should not be considered as an alternative to cash flows from operating, investing or financing activities. FCF may not be calculated the same for us as for othercompanies. FCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks,research analysts and others to assess our ability to make cash distributions and repay debt. Leverage Ratio Leverage ratio represents the outstanding principal of NRP's debt at the end of the period divided by the last twelve months' Adjusted EBITDA as definedabove. NRP believes that leverage ratio is a useful measure to management and investors to evaluate and monitor the indebtedness of NRP relative to its ability togenerate income to service such debt and in understanding trends in NRP’s overall financial condition. Leverage ratio may not be calculated the same for us as for othercompanies and is not a substitute for, and should not be used in conjunction with, GAAP financial ratios. 29Table of Contents Executive Overview We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties inthe United States, including interests in coal and other natural resources and own a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), atrona ore mining and soda ash production business. Our common units trade on the New York Stock Exchange under the symbol "NRP." Our business is organized intotwo operating segments: Mineral Rights—consists of approximately 13 million acres of mineral interests and other subsurface rights across the United States. If combined in a single tract,our ownership would cover roughly 20,000 square miles. Our ownership provides critical inputs for the manufacturing of steel, electricity and basic building materials, aswell as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energyeconomy in the years to come. Soda Ash—consists of our 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining and soda ash production business located in the GreenRiver Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicalsindustries. Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest andfinancing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment. Our financial results by segment for the year ended December 31, 2023 are as follows: Operating Segments Corporate and (In thousands) Mineral Rights Soda Ash Financing Total Revenues and other income $296,612 $73,397 $— $370,009 Net income (loss) $245,527 $73,140 $(40,232) $278,435 Asset impairments 556 — — 556 Net income (loss) excluding asset impairments $246,083 $73,140 $(40,232) $278,991 Adjusted EBITDA (1) $264,554 $81,221 $(26,111) $319,664 Cash flow provided by (used in) continuing operations Operating activities $259,983 $81,207 $(30,212) $310,978 Investing activities $5,426 $— $(10) $5,416 Financing activities $(583) $— $(342,913) $(343,496)Distributable cash flow (1) $265,409 $81,207 $(30,222) $316,394 Free cash flow (1) $262,446 $81,207 $(30,222) $313,431 (1)See"—Results of Operations" below for reconciliations to the most comparable GAAP financial measures. 30Table of Contents Current Results/Market Commentary Business Outlook and Quarterly Distributions We generated $311.0 million of operating cash flow and $313.4 million of free cash flow during the year ended December 31, 2023, and ended the yearwith $71.2 million of liquidity consisting of $12.0 million of cash and cash equivalents and $59.2 million of borrowing capacity under our Opco Credit Facility. Asof December 31, 2023 our leverage ratio was 0.5x. In 2023, we received notices from holders of the Class A Convertible Preferred Units representing limited partner interests in NRP (the "preferred units") exercisingtheir right to either convert or redeem, at our election, an aggregate of 83,333 preferred units. We chose to redeem the preferred units for $83.3 million in cash rather thanconverting them into common units. In 2023, we also executed negotiated transactions with holders of the preferred units pursuant to which we repurchased and retiredan aggregate of 95,001 preferred units for $95.0 million in cash. Of the originally issued 250,000 preferred units, 71,666 preferred units remain outstanding as of December31, 2023. Following these redemptions and repurchases, the subject units were retired and no longer remain outstanding and Blackstone ceased to own any preferredunits. All rights of Blackstone related to its ownership of preferred units ceased, including Blackstone's right to appoint a board designee. In 2023, we negotiated transactions with holders of the warrants to purchase common units (the "warrants") pursuant to which we repurchased and retired anaggregate of 752,500 warrants with a strike price of $22.81 and 710,000 warrants with a strike price of $34.00 for approximately $56.1 million in cash. In January and February 2024, holders of our warrants exercised a total of 1,219,665 warrants with a strike price of $34.00. We settled the warrants on a net basiswith a total of $56 million in cash and 198,767 common units. Following these transactions, of the originally issued 4,000,000 warrants, 320,335 warrants with a strike priceof $34.00 remain outstanding. In February 2024, we exercised our option under the Opco Credit Facility to increase the total aggregate commitment under the Opco Credit Facility twice, initiallyby $30 million from $155.0 million to $185.0 million and subsequently by $15.0 million from $185.0 million to $200.0 million. These increases in the total aggregatecommitment were made pursuant to an accordion feature of the Opco Credit Facility. In connection with the initial increase, a new lender joined the lending group with acommitment of $30.0 million. The Opco Credit Facility otherwise continues to operate under its existing terms and conditions in all material respects. In February 2024, the Board of Directors declared a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2023 as well as a$2.15 million cash distribution on the preferred units with respect to the fourth quarter of 2023. Additionally, NRP has announced it will pay special cash distribution of$2.44 in March 2024 to help cover unitholder tax liabilities associated with owning NRP's common units in 2023. Future distributions on our common and preferred unitswill be determined on a quarterly basis by the Board of Directors. The Board of Directors considers numerous factors each quarter in determining cash distributions,including profitability, cash flow, debt service obligations, market conditions and outlook, estimated unitholder income tax liability and the level of cash reserves that theBoard of Directors determines is necessary for future operating and capital needs. Mineral Rights Business Segment Revenues and other income during the year ended December 31, 2023 decreased $32.6 million, or 10%, as compared to the prior year primarily due to decreasedmetallurgical coal sales prices, decreased revenues from oil and gas royalties, lower transportation and processing services revenues and certain carbon neutral initiativetransactions entered into in 2022. Cash provided by operating activities and free cash flow decreased $2.8 million and $2.1 million, respectively, compared to the prioryear period primarily due to the lower revenues during the year ended December 31, 2023 as compared to the prior year period. Metallurgical and thermal coal prices saw significant variability in 2023, and were off the record highs seen in 2022, but finished the year strong relative tohistorical norms. We believe limitations from ongoing labor shortages, access to capital, and inflationary pressures should provide continued price support formetallurgical and thermal coal in 2024, despite headwinds from lower steel demand and the long-term secular decline in thermal energy production. We continue to explore and identify carbon neutral revenue sources across our large portfolio of surface, mineral, and timber assets, including the permanentsequestration of carbon dioxide underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy, as well as lithiumproduction. While the timing and likelihood of additional cash flows being realized from these activities is uncertain, we believe our large ownership footprintthroughout the United States provides additional opportunities to create value in this regard with minimal capital investment by us. Soda Ash Business Segment Revenues and other income during the year ended December 31, 2023 were higher by $13.6 million, or 23%, as compared to the prior year primarily due to highersales prices driven by strong demand domestically, partially offset by lower soda ash production and sales volumes. Cash provided by operating activities and free cash flow during the year ended December 31, 2023 increased $36.5 million as compared to the prior year period dueto higher distributions received from Sisecam Wyoming in 2023 stemming from Sisecam Wyoming's strong operating performance in the first half of the year. Strong sales prices at Sisecam Wyoming for the year ended December 31, 2023 more than offset input cost inflation, supply chain difficulties, and the influx ofsupply from China in the latter part of the year. However, we believe this increase in global soda ash production will result in an oversupplied market and a decline insoda ash prices in 2024. 31Table of Contents Results of Operations Year Ended December 31, 2023 and 2022 Compared Revenues and Other Income The following table includes our revenues and other income by operating segment: For the Year Ended December 31, Increase Percentage Operating Segment (In thousands) 2023 2022 (Decrease) Change Mineral Rights $296,612 $329,167 $(32,555) (10)%Soda Ash 73,397 59,795 13,602 23%Total $370,009 $388,962 $(18,953) (5)% 32Table of Contents The changes in revenues and other income are discussed for each of the operating segments below: Mineral Rights The following table presents coal sales volumes, coal royalty revenue per ton and coal royalty revenues by major coal producing region, the significant categoriesof other revenues and other income: For the Year Ended December 31, Increase Percentage (In thousands, except per ton data) 2023 2022 (Decrease) Change Coal sales volumes (tons) Appalachia Northern 1,145 1,696 (551) (32)%Central 13,927 13,646 281 2%Southern 2,670 1,784 886 50%Total Appalachia 17,742 17,126 616 4%Illinois Basin 8,119 11,135 (3,016) (27)%Northern Powder River Basin 4,589 4,288 301 7%Gulf Coast 1,477 385 1,092 284%Total coal sales volumes 31,927 32,934 (1,007) (3)% Coal royalty revenue per ton Appalachia Northern $7.15 $8.75 $(1.60) (18)%Central 8.95 10.47 (1.52) (15)%Southern 12.81 13.50 (0.69) (5)%Illinois Basin 3.61 2.50 1.11 44%Northern Powder River Basin 4.50 4.07 0.43 11%Gulf Coast 0.66 0.58 0.08 14%Combined average coal royalty revenue per ton 6.83 6.90 (0.07) (1)% Coal royalty revenues Appalachia Northern $8,192 $14,836 $(6,644) (45)%Central 124,631 142,930 (18,299) (13)%Southern 34,205 24,076 10,129 42%Total Appalachia 167,028 181,842 (14,814) (8)%Illinois Basin 29,350 27,856 1,494 5%Northern Powder River Basin 20,666 17,437 3,229 19%Gulf Coast 969 223 746 335%Unadjusted coal royalty revenues 218,013 227,358 (9,345) (4)%Coal royalty adjustment for minimum leases (2) (402) 400 100%Total coal royalty revenues $218,011 $226,956 $(8,945) (4)% Other revenues Production lease minimum revenues $3,322 $5,854 $(2,532) (43)%Minimum lease straight-line revenues 19,389 18,792 597 3%Carbon neutral initiative revenues 2,969 8,600 (5,631) (65)%Wheelage revenues 12,191 13,961 (1,770) (13)%Property tax revenues 6,219 5,878 341 6%Coal overriding royalty revenues 2,175 3,434 (1,259) (37)%Lease amendment revenues 3,070 3,201 (131) (4)%Aggregates royalty revenues 2,876 3,299 (423) (13)%Oil and gas royalty revenues 7,387 16,161 (8,774) (54)%Other revenues 1,124 877 247 28%Total other revenues $60,722 $80,057 $(19,335) (24)%Royalty and other mineral rights $278,733 $307,013 $(28,280) (9)%Transportation and processing services revenues 14,923 21,072 (6,149) (29)%Gain on asset sales and disposals 2,956 1,082 1,874 173%Total Mineral Rights segment revenues and other income $296,612 $329,167 $(32,555) (10)% 33Table of Contents Coal Royalty Revenues Approximately 70% of coal royalty revenues and approximately 50% of coal royalty sales volumes were derived from metallurgical coal during the year endedDecember 31, 2023. Total coal royalty revenues decreased $8.9 million from 2022 to 2023. The discussion by region is as follows: •Appalachia: Coal royalty revenues decreased $14.8 million primarily due to decreased metallurgical coal sales prices during the year ended December 31, 2023, ascompared to the prior year.•Illinois Basin: Coal royalty revenues increased $1.5 million primarily due to higher thermal coal sales prices, partially offset by lower coal sales volumes as comparedto the prior year.•Northern Powder River Basin: Coal royalty revenues increased $3.2 million due to increased sales volumes and higher coal sales prices during the year endedDecember 31, 2023, as compared to the prior year. The increase in sales volumes was due to our lessee mining more on our property during 2023 as compared to2022 in accordance with its mine plan. Other Revenues Other revenues decreased $19.3 million during the year ended December 31, 2023 as compared to the prior year primarily due to the following:•An $8.8 million decrease in oil and gas revenues primarily as a result of decreased natural gas prices as compared to the prior year;•A $5.6 million decrease in carbon neutral initiative revenues as compared to the prior year. Carbon neutral initiative revenues recognized in 2023 primarily related tosubsurface CO2 storage and forest offset credits. Carbon neutral initiative revenues recognized in 2022 primarily related to subsurface CO2 storage and geothermalenergy transactions; and•A $2.5 million decrease in production lease minimum revenues primarily as a result of a decrease in breakage revenues as compared to the prior year. Transportation and Processing Services Revenues Transportation and processing services revenues decreased $6.1 million during the year ended December 31, 2023 as compared to the prior year primarily due to atemporary relocation of certain production off of NRP's coal reserves. The fee per ton associated with the transportation and processing of the non-NRP coal is less thanthe fee per ton associated with the transportation and processing of NRP coal. Soda Ash Revenues and other income related to our Soda Ash segment increased $13.6 million compared to the prior year primarily due to higher sales prices driven bystrong demand domestically, partially offset by lower soda ash production and sales volumes. Operating and Other Expenses The following table presents the significant categories of our consolidated operating and other expenses: For the Year Ended December 31, Increase Percentage (In thousands) 2023 2022 (Decrease) Change Operating expenses Operating and maintenance expenses $32,315 $34,903 $(2,588) (7)%Depreciation, depletion and amortization 18,489 22,519 (4,030) (18)%General and administrative expenses 26,111 21,852 4,259 19%Asset impairments 556 4,457 (3,901) (88)%Total operating expenses $77,471 $83,731 $(6,260) (7)% Other expenses, net Interest expense, net $14,103 $26,274 $(12,171) (46)%Loss on extinguishment of debt — 10,465 (10,465) (100)%Total other expenses, net $14,103 $36,739 $(22,636) (62)% Total operating expenses decreased $6.3 million primarily due to the following:•A $2.6 million decrease in operating and maintenance expenses primarily as a result of lower overriding royalty expense from an agreement with Western PocahontasProperties Limited Partnership ("WPPLP") in 2023 as compared to 2022. This overriding royalty expense is fully offset by coal royalty revenue we receive from thisproperty.•A $3.9 million decrease in asset impairments as compared to the prior year.•A $4.0 million decrease in depreciation, depletion and amortization expense primarily driven by lower Illinois Basin coal royalty sales volumes during the year endedDecember 31, 2023, as compared to the prior year. These decreases were partially offset by a $4.3 million increase in general and administrative expenses primarily due to higher long-term incentive expense duringthe year ended December 31, 2023, as compared to the prior year. Total other expenses, net decreased $22.6 million primarily due to a $12.2 million decrease in interest expense, net as a result of less debt outstanding during 2023as compared to the prior year, and a $10.5 million decrease related to the loss on early extinguishment of debt related to the retirement of the 2025 Senior Notes duringthe year ended December 31, 2022. 34Table of Contents Adjusted EBITDA (Non-GAAP Financial Measure) The following table reconciles net income (loss) (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment: Operating Segments Corporate and For the Year Ended (In thousands) Mineral Rights Soda Ash Financing Total December 31, 2023 Net income (loss) $245,527 $73,140 $(40,232) $278,435 Less: equity earnings from unconsolidated investment — (73,397) — (73,397)Add: total distributions from unconsolidated investment — 81,478 — 81,478 Add: interest expense, net — — 14,103 14,103 Add: depreciation, depletion and amortization 18,471 — 18 18,489 Add: asset impairments 556 — — 556 Adjusted EBITDA $264,554 $81,221 $(26,111) $319,664 December 31, 2022 Net income (loss) $267,448 $59,635 $(58,591) $268,492 Less: equity earnings from unconsolidated investment — (59,795) — (59,795)Add: total distributions from unconsolidated investment — 44,835 — 44,835 Add: interest expense, net — — 26,274 26,274 Add: loss on extinguishment of debt — — 10,465 10,465 Add: depreciation, depletion and amortization 22,519 — — 22,519 Add: asset impairments 4,457 — — 4,457 Adjusted EBITDA $294,424 $44,675 $(21,852) $317,247 Net income increased $9.9 million primarily due to the decrease in operating and other expenses, net, partially offset by the decrease in revenues and other income,both discussed above. Adjusted EBITDA increased $2.4 million primarily due to a $36.5 million increase in Adjusted EBITDA within our Soda Ash segment as a result ofhigher cash distributions received from Sisecam Wyoming during the year ended December 31, 2023 as compared to the prior year due to Sisecam Wyoming's strongoperating performance in the first half of 2023. This increase was partially offset by a $29.9 million decrease in Adjusted EBITDA within our Mineral Rights segment as aresult of lower revenues and other income during the year ended December 31, 2023 as discussed above and a $4.3 million decrease in Adjusted EBITDA within ourCorporate and Financing segment as a result of the increase in general and administrative expenses during the year ended December 31, 2023 as discussed above. Distributable Cash Flow ("DCF") and Free Cash Flow ("FCF") (Non-GAAP Financial Measures) The following table presents the three major categories of the statement of cash flows by business segment: Operating Segments Corporate and For the Year Ended (In thousands) Mineral Rights Soda Ash Financing Total December 31, 2023 Cash flow provided by (used in) Operating activities $259,983 $81,207 $(30,212) $310,978 Investing activities 5,426 — (10) 5,416 Financing activities (583) — (342,913) (343,496) December 31, 2022 Cash flow provided by (used in) Operating activities $262,807 $44,672 $(40,641) $266,838 Investing activities 2,806 — (118) 2,688 Financing activities (614) — (365,341) (365,955) 35Table of Contents The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCFand FCF: Operating Segments Corporate and For the Year Ended (In thousands) Mineral Rights Soda Ash Financing Total December 31, 2023 Net cash provided by (used in) operating activities $259,983 $81,207 $(30,212) $310,978 Add: proceeds from asset sales and disposals 2,963 — — 2,963 Add: return of long-term contract receivable 2,463 — — 2,463 Less: maintenance capital expenditures — — (10) (10)Distributable cash flow $265,409 $81,207 $(30,222) $316,394 Less: proceeds from asset sales and disposals (2,963) — — (2,963)Free cash flow $262,446 $81,207 $(30,222) $313,431 Operating Segments Corporate and For the Year Ended (In thousands) Mineral Rights Soda Ash Financing Total December 31, 2022 Net cash provided by (used in) operating activities $262,807 $44,672 $(40,641) $266,838 Add: proceeds from asset sales and disposals 1,083 — — 1,083 Add: return of long-term contract receivable 1,723 — — 1,723 Less: maintenance capital expenditures — — (118) (118)Distributable cash flow $265,613 $44,672 $(40,759) $269,526 Less: proceeds from asset sales and disposals (1,083) — — (1,083)Free cash flow $264,530 $44,672 $(40,759) $268,443 Cash provided by operating activities, DCF and FCF increased $44.1 million, $46.9 million and $45.0 million, respectively from 2022 to 2023. The discussion bysegment is as follows. •Mineral Rights Segment: Cash provided by operating activities, DCF and FCF decreased $2.8 million, $0.2 million and $2.1 million, respectivelyprimarily due to the segment's decrease in revenues and other income as discussed above. •Soda Ash Segment: Cash provided by operating activities, DCF and FCF increased $36.5 million as a result of higher cash distributions received fromSisecam Wyoming in 2023 driven by Sisecam Wyoming's strong operating performance in the first half of 2023. •Corporate and Financing Segment: Cash used in operating activities decreased $10.4 million and DCF and FCF increased $10.5 million primarily due tolower cash paid for interest in 2023 as a result of the retirement of the 2025 Senior Notes in 2022. For discussion of our Results of Operations comparing 2022 to 2021, refer to our 2022 Annual Report on Form 10-K filed March 3, 2023 under Part II, "Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations." 36Table of Contents Liquidity and Capital Resources Current Liquidity As of December 31, 2023, we had total liquidity of $71.2 million, consisting of $12.0 million of cash and cash equivalents and $59.2 million in borrowing capacityunder our Opco Credit Facility. We have debt service obligations, including approximately $31 million of principal repayments on Opco’s senior notes in 2024. Asof December 31, 2023 our leverage ratio was 0.5x. The following table calculates our leverage ratio: (In thousands) For the Year EndedDecember 31, 2023 Adjusted EBITDA $319,664 Debt—at December 31, 2023 $155,525 Leverage Ratio 0.5x Cash Flows Year Ended December 31, 2023 and 2022 Compared Cash flows provided by operating activities increased $44.1 million, from $266.8 million during the year ended December 31, 2022 to $311.0 million during the yearended December 31, 2023 due to increased cash flow within our Soda Ash and Corporate and Financing segments, partially offset by decreased cash flow withinour Mineral Rights segment, all discussed above. Cash flows used in financing activities decreased $22.5 million, from $366.0 million used during the year ended December 31, 2022 to $343.5 million used during theyear ended December 31, 2023 primarily due to the following: •$300.0 million of cash used to retire the 2025 Senior Notes in 2022; •$178.8 million of increased borrowings on the Opco Credit Facility in 2023; •$19.3 million of cash used to redeem the preferred units paid-in-kind in 2022; •$9.1 million of decreased cash used for other items, net primarily due to the premiums paid related to the retirement of the 2025 Senior Notes in 2022;and •$8.2 million of decreased cash used for preferred unit distributions as a result of the preferred unit redemptions in 2023. These decreases in cash flow used were partially offset by the following: •$178.3 million of cash used to redeem the preferred units in 2023; •$223.0 million of cash used to repay a portion of the Opco Credit Facility in 2023; •$56.1 million of cash used to settle certain of our warrants in 2023; and •$35.5 million of increased cash distributions to common unitholders and the general partner as a result of the special cash distribution of $2.43/unitmade in the first quarter of 2023 in addition to increasing our common unit distributions to $0.75/unit beginning in the second quarter of 2022. For discussion of our Cash Flows comparing 2022 to 2021, refer to our 2022 Annual Report on Form 10-K filed March 3, 2023 under Part II, "Item 7. Management'sDiscussion and Analysis of Financial Condition and Results of Operations." 37Table of Contents Capital Resources and Obligations Debt, Net We had the following debt outstanding as of December 31, 2023 and 2022: December 31, (In thousands) 2023 2022 Current portion of long-term debt, net $30,785 $39,076 Long-term debt, net 124,273 129,205 Total debt, net $155,058 $168,281 We have been and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information regardingour debt and the agreements governing our debt, including the covenants contained therein, see "Item 8. Financial Statements and Supplementary Data—Note 11. Debt,Net" in this Annual Report on Form 10-K. Debt Obligations The following table reflects our long-term, non-cancelable debt obligations as of December 31, 2023: Payments Due by Period Debt Obligations (In thousands) Total 2024 2025 2026 2027 2028 Thereafter Opco: Debt principal payments (including current maturities) (1) $155,525 $31,028 $14,332 $14,331 $95,834 $- $— Debt interest payments (2) 4,899 2,724 1,450 725 — — — Total $160,424 $33,752 $15,782 $15,056 $95,834 $— $— (1)The amounts indicated in the table include principal due on Opco’s senior notes and credit facility. (2)The amounts indicated in the table include interest due on Opco’s senior notes. Preferred Units and Warrants As of December 31, 2023 there were 71,666 preferred units outstanding. As of December 31, 2022 there were 250,000 preferred units outstanding. As of December31, 2023 there were 1,540,000 warrants with a strike price of $34.00 outstanding. As of December 31, 2022 there were 3,002,500 warrants outstanding, which includedwarrants to purchase 752,500 common units at a strike price of $22.81 and warrants to purchase 2,250,00 common units with a strike price of $34.00. For more informationon our preferred units and warrants, see "Item 8. Financial Statements and Supplementary Data—Note 4. Class A Convertible Preferred Units and Warrants" in thisAnnual Report on Form 10-K. Inflation Despite rising costs beginning in 2021 and continuing into 2023, inflation did not have a material impact on operations for the years ended December 31, 2023,2022 and 2021. Environmental Regulation For additional information on environmental regulation that may have a material impact on our business, see "Items 1. and 2. Business and Properties—Regulationand Environmental Matters." Related Party Transactions The information required by this Item is included under "Item 8. Financial Statements and Supplementary Data—Note 13. Related Party Transactions" and "Item13. Certain Relationships and Related Transactions, and Director Independence" in this Annual Report on Form 10-K and is incorporated by reference herein. 38Table of Contents Summary of Critical Accounting Estimates Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management tomake estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See "Item 8. Financial Statements and SupplementaryData—Note 2. Summary of Significant Accounting Policies" in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significantaccounting policies. The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements.We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates. Revenues Mineral Rights Segment Revenues Royalty-based leases. Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the optionto extend the lease for additional terms. For these types of leases, the lessees generally make payments to us based on the greater of a percentage of the gross salesprice or a fixed price per ton of mineral mined and sold. Most of our coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts,either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally range from three to fiveyears. We have defined our coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell our coal or aggregates over thelease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production would exceed consideration expectedto be received from minimum payments over the lease term. As a result of this evaluation, revenue recognition from our royalty-based leases is based on either production or minimum payments as follows:•Production Leases: Leases for which we expect that consideration from production will be greater than consideration from minimums over the lease term. Revenuefor these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenueswhen recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, we recognize breakage revenue from minimumswhen we determine that recoupment is remote. This breakage revenue is included in production lease minimum revenues.•Minimum Leases: Leases for which we expect that consideration from minimums will be greater than consideration from production over the lease term. Revenue forthese leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues. This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease. Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregatesmineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimatedeconomic tonnage as estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of oureconomic tonnage include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statisticalanalysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of economic tonnage, includingmany factors beyond our control. Estimates of economically recoverable tonnage depend upon a number of variable factors and assumptions, any one of which may, ifincorrect, result in an estimate that varies considerably from actual results. Asset Impairment We have developed procedures to evaluate our long-lived assets, including intangible assets, for possible impairment periodically or whenever events or changesin circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific events such as areduction in economically recoverable tons or production ceasing on a property for an extended period. A long-lived asset is deemed impaired when the future expectedundiscounted cash flows from its use and disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usuallydetermined based upon the present value of the projected future cash flow compared to the asset's net book value. We believe our estimates of cash flows and discountrates are consistent with those of principal market participants. We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of suchinvestment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fairvalue 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 valueand 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 financialstatements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows usingdiscount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, ifappropriate. Recent Accounting Standards In November 2023, the FASB issued ASU No. 2023-07—Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures ("ASU 2023-07").The amendments in ASU 2023-07 improve reportable segment disclosure requirements, primarily through enhanced disclosures about segment expenses. The guidanceis effective for annual and interim periods beginning after December 15, 2023 and is to be adopted retrospectively to all prior periods presented in the financialstatements. We do not expect the adoption of ASU 2023-07 to have a material effect on our Consolidated Financial Statements. 39Table of Contents ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below: Commodity Price Risk Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices.Historically, coal prices have been volatile, with prices fluctuating widely, and are likely to continue to be volatile. Depressed prices in the future would have a negativeimpact on our future financial results. In particular, substantially lower prices would significantly reduce revenues and could potentially trigger an impairment of our coalproperties or a violation of certain financial debt covenants. Because substantially all our reserves are coal, changes in coal prices have a more significant impact on ourfinancial results. We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts aswell as on the spot market. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts withterms of one year or more. Our lessees' failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees' operations andadversely affect our future financial results. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coalprices. The market price of soda ash and energy costs directly affects the profitability of Sisecam Wyoming's operations. If the market price for soda ash declines,Sisecam Wyoming's sales revenues will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile and are likelyto remain volatile in the future. The following table shows the fluctuations of our commodity prices over the past three years: 2023 2022 2021 Combined average coal royalty revenue per ton $6.83 $6.90 $4.47 Soda ash average sales price per short ton $284.97 $270.42 $191.97 Interest Rate Risk Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to variable interest rates based upon SOFR.At December 30, 2023, we had $95.8 million in borrowings outstanding under the Opco Credit Facility. If interest rates were to increase by 1%, annual interest expensewould increase approximately $9.6 million, assuming the same principal amount remained outstanding during the year. Fair Value of Financial Assets and Liabilities Our financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The carrying amounts reported on the ConsolidatedBalance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. We use available market data and valuation methodologies toestimate the fair value of our debt and contract receivable. The following table shows the carrying value and estimated fair value of our debt and contract receivable: December 31, 2023 2022 Carrying Estimated Carrying Estimated (In thousands) Fair Value Hierarchy Level Value Fair Value Value Fair Value Debt: Opco Senior Notes (1) 3 $59,224 $56,533 $98,281 $96,060 Opco Credit Facility (2) 3 95,834 95,384 70,000 70,000 Assets: Contract receivable, net (current and long-term) (3) 3 $28,946 $24,492 $31,371 $24,833 (1)The fair value of the Opco Senior Notes was estimated by management utilizing the present value replacement method incorporating the interest rate of the OpcoCredit Facility.(2)The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates andthe terms of the credit facility allow the Partnership to repay this debt at any time without penalty.(3)The fair value of the Partnership's contract receivable was determined based on the present value of future cash flow projections related to the underlying asset at adiscount rate of 15% at December 31, 2023 and 2022. 40Table of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS PageReport of Ernst & Young LLP, Independent Registered Public Accounting Firm (PCAOB ID 42)42Report of BDO USA, P.C. Independent Registered Public Accounting Firm (PCAOB ID 243)44Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm (PCAOB ID 34)46Consolidated Balance Sheets as of December 31, 2023 and 202247Consolidated Statements of Comprehensive Income for the years ended December 31, 2023, 2022 and 202148Consolidated Statements of Partners’ Capital for the years ended December 31, 2023, 2022 and 202149Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 202150Notes to Consolidated Financial Statements51 41Table of Contents Report of Independent Registered Public Accounting Firm To the Partners of Natural Resource Partners L.P. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. (the Partnership) as of December 31, 2023 and 2022, the relatedconsolidated statements of comprehensive income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2023, and the relatednotes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the reports of other auditors, the consolidatedfinancial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2023 and 2022, and the results of its operations and itscash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles. We did not audit the financial statements of Sisecam Wyoming LLC (Sisecam Wyoming), a limited liability company in which the Partnership has a 49% interest. In theconsolidated financial statements, the Partnership’s investment in Sisecam Wyoming is stated at $277 million and $306 million as of December 31, 2023 and 2022,respectively, and the Partnership’s equity in the net income of Sisecam Wyoming is stated at $73 million in 2023, $60 million in 2022 and $22 million in 2021. Thosestatements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for SisecamWyoming, is based solely on the reports of other auditors. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal controlover financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission (2013 framework), and our report dated March 7, 2024 expressed an unqualified opinion thereon. Basis for Opinion These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statementsbased on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance withthe U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assuranceabout whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks ofmaterial misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures includedexamining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principlesused and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the reportof other auditors provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to becommunicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especiallychallenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financialstatements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accountor disclosure to which it relates. 42Table of Contents Impairment Assessment of Mineral Rights Description of the MatterAt December 31, 2023, the Partnership’s mineral rights, net totaled $394 million. As described in Note 2 to theconsolidated financial statements, the Partnership evaluates its long-lived assets (inclusive of mineral rights) forpossible impairment whenever events or changes in circumstances indicate that the carrying amounts of the assetmay not be recoverable. Management evaluates various qualitative and quantitative factors in determining whether ornot events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.Potential events or circumstances include, but are not limited to, reduction in economically recoverable tons orproduction ceasing on a property for an extended period. Auditing the Partnership’s impairment indicator assessment involved our subjective judgment because, indetermining whether an impairment indicator occurred, significant uncertainty exists with judgments managementutilizes regarding the likelihood of future production and the likelihood of potential contract renewals ormodifications, which rely on information reported by the Partnership’s lessee operators. How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over thePartnership’s impairment assessment process. We tested controls over the Partnership’s process for identifying andevaluating potential indicators of impairment pertaining to mineral rights and the related significant judgments. To test the Partnership’s mineral rights impairment assessment, our audit procedures included, among others, makinginquiries of management (including personnel in operations) to understand changes in business, and evaluating thesignificant judgments used in the Partnership’s assessment. Specifically, we corroborated reserve information to newreserve studies when available. Additionally, we inspected the termination or significant modification of royalty-based lease contracts. We searched for and evaluated other publicly available information, such as legislative orregulatory changes and bankruptcy filings pertaining to their material lessees, that corroborates or contradictsmanagement’s assessment. /s/ Ernst & Young LLP We have served as the Partnership’s auditor since 2002. Houston, TexasMarch 7, 2024 43Table of Contents Report of Independent Registered Public Accounting Firm Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying balance sheets of Sisecam Wyoming LLC (the “Company”) as of December 31, 2023 and 2022, the related statements of operationsand comprehensive income, members’ equity, and cash flows for each of the years then ended, and the related notes (collectively referred to as the “financialstatements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and theresults of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States ofAmerica. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statementsbased on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required tobe independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States ofAmerica. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of materialmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financialreporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinionon the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to becommunicated to the Board of Managers and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especiallychallenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as awhole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures towhich it relates. 44Table of Contents Agreements and Transactions with Affiliates As presented in the financial statements and further described in Note 13 to the financial statements, the Company’s accounts receivable – affiliates, due to affiliates,cost of products sold – affiliates, selling, general and administrative expenses – affiliates account balances were $55,171 thousand, $4,882 thousand, $5,343 thousand,and $20,753 thousand as of and for the year ended December 31, 2023, respectively. As the Company is a subsidiary and investee within two different global groupstructures, agreements directly between the Company and other affiliates, or indirectly between affiliates the Company does not control, can have a significant impacton recorded amounts or disclosures in the Company's financial statements, including any commitments and contingencies between the Company and affiliates or,potentially, third parties. We identified the agreements and transactions with affiliates as a critical audit matter. Management’s judgment was required in performing cost allocations and auditingthese elements involved especially challenging auditor judgement due to the nature and extent of audit effort and knowledge required on the relationships and potentialrelated costs allocations to address these matters. The primary procedures we performed to address this critical audit matter included: •Testing the Company’s affiliate listing for the year ended December 31, 2023, including testing the completeness and accuracy of the identification of theCompany’s affiliate relationships, transactions, and commitments and contingencies originating outside of the Company by: (i) reading internal minutes, publicly available financial filings and news sources related to the Company and its affiliates outside of the Company, (ii) confirming with the Company’s ultimate parent companies the affiliate relationships, transactions, and commitments and contingencies are identified anddisclosed by the Company, (iii) testing the accuracy of the cost allocations to ensure they are being recorded in the appropriate financial statement accounts. /s/ BDO USA, P.C. We have served as the Company's auditor since 2022. Charlotte, North Carolina March 7, 2024 45Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying statements of operations and comprehensive income, members' equity, and cash flows of Sisecam Wyoming LLC (the “Company”)for the year ended December 31, 2021, and the related notes that are included in Exhibit 99.1 (collectively referred to as the "financial statements"). In our opinion, thefinancial statements present fairly, in all material respects, the results of the Company’s operations and cash flows for the year ended December 31, 2021, in conformitywith accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statementsbased on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to beindependent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement,whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part ofour audit, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness ofthe Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. /s/ Deloitte & Touche LLP Atlanta, GeorgiaMarch 15, 2022 We began serving as the Company's auditor in 2008. In 2022 we became the predecessor auditor. 46Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED BALANCE SHEETS December 31, (In thousands, except unit data) 2023 2022 ASSETS Current assets Cash and cash equivalents $11,989 $39,091 Accounts receivable, net 41,086 42,701 Other current assets, net 2,218 1,822 Total current assets $55,293 $83,614 Land 24,008 24,008 Mineral rights, net 394,483 412,312 Intangible assets, net 13,682 14,713 Equity in unconsolidated investment 276,549 306,470 Long-term contract receivable, net 26,321 28,946 Other long-term assets, net 7,540 7,068 Total assets $797,876 $877,131 LIABILITIES AND CAPITAL Current liabilities Accounts payable $885 $1,992 Accrued liabilities 12,987 11,916 Accrued interest 584 989 Current portion of deferred revenue 4,599 6,256 Current portion of long-term debt, net 30,785 39,076 Total current liabilities $49,840 $60,229 Deferred revenue 38,356 40,181 Long-term debt, net 124,273 129,205 Other non-current liabilities 7,172 5,472 Total liabilities $219,641 $235,087 Commitments and contingencies (see Note 15) Class A Convertible Preferred Units (71,666 and 250,000 units issued and outstanding at December 31, 2023 and 2022,respectively, at $1,000 par value per unit; liquidation preference of $1,850 per unit at December 31, 2023 and 2022) (SeeNote 4) $47,181 $164,587 Partners’ capital Common unitholders’ interest (12,634,642 and 12,505,996 units issued and outstanding at December 31, 2023 and2022, respectively) $503,076 $404,799 General partner’s interest 8,005 5,977 Warrant holders’ interest 23,095 47,964 Accumulated other comprehensive income (loss) (3,122) 18,717 Total partners' capital $531,054 $477,457 Total liabilities and partners' capital $797,876 $877,131 The accompanying notes are an integral part of these consolidated financial statements. 47Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Year Ended December 31, (In thousands, except per unit data) 2023 2022 2021 Revenues and other income Royalty and other mineral rights $278,733 $307,013 $185,196 Transportation and processing services 14,923 21,072 9,052 Equity in earnings of Sisecam Wyoming 73,397 59,795 21,871 Gain on asset sales and disposals 2,956 1,082 245 Total revenues and other income $370,009 $388,962 $216,364 Operating expenses Operating and maintenance expenses $32,315 $34,903 $27,049 Depreciation, depletion and amortization 18,489 22,519 19,075 General and administrative expenses 26,111 21,852 17,360 Asset impairments 556 4,457 5,102 Total operating expenses $77,471 $83,731 $68,586 Income from operations $292,538 $305,231 $147,778 Other expenses, net Interest expense, net $(14,103) $(26,274) $(38,876)Loss on extinguishment of debt — (10,465) — Total other expenses, net $(14,103) $(36,739) $(38,876) Net income $278,435 $268,492 $108,902 Less: income attributable to preferred unitholders (16,719) (30,000) (31,609)Less: redemption of preferred units (60,929) — — Net income attributable to common unitholders and the general partner $200,787 $238,492 $77,293 Net income attributable to common unitholders $196,771 $233,722 $75,747 Net income attributable to the general partner 4,016 4,770 1,546 Net income per common unit (see Note 6) Basic $15.59 $18.72 $6.14 Diluted 13.08 13.39 4.81 Net income $278,435 $268,492 $108,902 Comprehensive income (loss) from unconsolidated investment and other (21,839) 15,506 2,889 Comprehensive income $256,596 $283,998 $111,791 The accompanying notes are an integral part of these consolidated financial statements. 48Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL Accumulated Other Total Common Unitholders General Warrant Comprehensive Partners' (In thousands) Units Amounts Partner Holders Income (Loss) Capital Balance at December 31, 2020 12,261 $136,927 $459 $66,816 $322 $204,524 Net income (1) — 106,724 2,178 — — 108,902 Distributions to common unitholders and the generalpartner — (22,192) (453) — — (22,645)Distributions to preferred unitholders — (30,519) (623) — — (31,142)Issuance of unit-based awards 90 — — — — — Unit-based awards amortization and vesting, net — 2,647 — — — 2,647 Capital contribution — — 32 — — 32 Warrant settlement — 9,475 194 (18,852) — (9,183)Comprehensive income from unconsolidatedinvestment and other — — — — 2,889 2,889 Balance at December 31, 2021 12,351 $203,062 $1,787 $47,964 $3,211 $256,024 Net income (2) — 263,122 5,370 — — 268,492 Distributions to common unitholders and the generalpartner — (33,697) (687) — — (34,384)Distributions to preferred unitholders — (29,653) (605) — — (30,258)Issuance of unit-based awards 155 — — — — — Unit-based awards amortization and vesting, net — 1,965 — — — 1,965 Capital contribution — — 112 — — 112 Comprehensive income from unconsolidatedinvestment and other — — — — 15,506 15,506 Balance at December 31, 2022 12,506 $404,799 $5,977 $47,964 $18,717 $477,457 Net income (3) — 272,866 5,569 — — 278,435 Redemptions of preferred units — (59,710) (1,219) — — (60,929)Distributions to common unitholders and the generalpartner — (68,510) (1,398) — — (69,908)Distributions to preferred unitholders — (21,628) (441) — — (22,069)Issuance of unit-based awards 129 — — — — — Unit-based awards amortization and vesting, net — 5,854 — — — 5,854 Capital contribution — — 142 — — 142 Warrant settlements — (30,595) (625) (24,869) — (56,089)Comprehensive loss from unconsolidated investmentand other — — — — (21,839) (21,839)Balance at December 31, 2023 12,635 $503,076 $8,005 $23,095 $(3,122) $531,054 (1)Net income includes $31.6 million of income attributable to preferred unitholders that accumulated during the period, of which $31.0 million is allocated to thecommon unitholders and $0.6 million is allocated to the general partner.(2)Net income includes $30.0 million of income attributable to preferred unitholders that accumulated during the period, of which $29.4 million is allocated to thecommon unitholders and $0.6 million is allocated to the general partner.(3)Net income includes $16.7 million of income attributable to preferred unitholders that accumulated during the period, of which $16.4 million is allocated to thecommon unitholders and $0.3 million is allocated to the general partner. The accompanying notes are an integral part of these consolidated financial statements. 49Table of Contents NATURAL RESOURCE PARTNERS L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year Ended December 31, (In thousands) 2023 2022 2021 Cash flows from operating activities Net income $278,435 $268,492 $108,902 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 18,489 22,519 19,075 Distributions from unconsolidated investment 81,478 44,835 11,270 Equity earnings from unconsolidated investment (73,397) (59,795) (21,871)Gain on asset sales and disposals (2,956) (1,082) (245)Loss on extinguishment of debt — 10,465 — Asset impairments 556 4,457 5,102 Bad debt expense 2,244 1,062 2,572 Unit-based compensation expense 10,910 5,773 4,039 Amortization of debt issuance costs and other 1,303 2,410 2,265 Change in operating assets and liabilities: Accounts receivable (164) (18,671) (14,415)Accounts payable (1,108) 37 570 Accrued liabilities (225) 935 3,020 Accrued interest (406) (224) (501)Deferred revenue (3,483) (15,424) 307 Other items, net (698) 1,049 1,714 Net cash provided by operating activities $310,978 $266,838 $121,804 Cash flows from investing activities Proceeds from asset sales and disposals $2,963 $1,083 $249 Return of long-term contract receivable 2,463 1,723 2,163 Capital expenditures (10) (118) — Net cash provided by investing activities $5,416 $2,688 $2,412 Cash flows from financing activities Debt borrowings $248,834 $70,000 $— Debt repayments (262,396) (339,396) (39,396)Distributions to common unitholders and the general partner (69,908) (34,384) (22,645)Distributions to preferred unitholders (22,069) (30,258) (15,571)Redemptions of preferred units (178,334) — — Redemption of preferred units paid-in-kind — (19,321) — Warrant settlements (56,089) — (9,183)Acquisition of non-controlling interest in BRP — — (1,000)Other items, net (3,534) (12,596) (691)Net cash used in financing activities $(343,496) $(365,955) $(88,486) Net increase (decrease) in cash and cash equivalents $(27,102) $(96,429) $35,730 Cash and cash equivalents at beginning of period 39,091 135,520 99,790 Cash and cash equivalents at end of period $11,989 $39,091 $135,520 Supplemental cash flow information: Cash paid for interest $13,856 $25,265 $37,378 Non-cash investing and financing activities: Preferred unit distributions paid-in-kind $— $— $15,571 The accompanying notes are an integral part of these consolidated financial statements. 50Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Nature of Operations Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP("NRP GP" or "general partner"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC ("managing general partner"), a Delawarelimited liability company. The Partnership engages principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the UnitedStates, including interests in coal and other natural resources and owns a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), a trona oremining and soda ash production business. The Partnership is organized into two operating segments further described in Note 7. Segment Information. As used in theseNotes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise statedor indicated by context. The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through onewholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole responsibility for conducting the Partnership's business and for managing itsoperations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board ofdirectors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability companyindirectly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Pursuant to the Board Representation andObservation Rights Agreement with certain entities controlled by funds affiliated with Blackstone Inc. (collectively referred to as "Blackstone") and affiliates ofGoldenTree Asset Management LP (collectively referred to as "GoldenTree"), Blackstone was entitled to appoint one of the directors of the board of directors of GPNatural Resource Partners LLC (the "Board of Directors"). In 2023, NRP repurchased all of Blackstone's preferred units which were subsequently retired and no longerremain outstanding, and all rights of Blackstone related thereto ceased as a result. In connection with the repurchase, Blackstone's board designee resigned from theBoard of Directors and all members of the Board of Directors are now appointed by RCM. 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in theUnited States of America ("GAAP"). The Consolidated Financial Statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries.The Partnership has an equity investment in Sisecam Wyoming through which it is able to exercise significant influence over but does not control the investee and isnot the primary beneficiary of the investee’s activities and is accounted for using the equity method. Intercompany transactions and balances have been eliminated.Reclassifications have been made to prior year amounts in the Consolidated Financial Statements to conform with current year presentation. These reclassifications hadno impact on previously reported total assets, total liabilities, partners' capital, net income, or cash flows from operating, investing or financing activities. Use of Estimates Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reportedamounts of assets and liabilities on the accompanying Consolidated Balance Sheets, the disclosure of contingent assets and liabilities at the date of the financialstatements, and the reported amounts of revenues and expenses on the accompanying Consolidated Statements of Comprehensive Income during the reporting period.Actual results could differ from those estimates. The most significant estimates pertain to coal and aggregates mineral rights and related cash flow estimates which areused to compute depreciation, depletion and amortization and impairments of coal and aggregates properties and related intangible assets and commitments andcontingencies. Fair Value The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as the price that would bereceived to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 12. Fair ValueMeasurements for further details. There are three levels of inputs that may be used to measure fair value:•Level 1—Quoted prices in active markets for identical assets or liabilities.•Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or otherinputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.•Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets andliabilities include financial assets and liabilities whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as wellas instruments for which the determination of fair value requires significant management judgment or estimation. 51Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Cash and Cash Equivalents The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents. Allowance for Doubtful Accounts The Partnership records an allowance for doubtful accounts for its accounts receivable and notes receivable comprised of estimated credit risk and non-credit risk(e.g., legal disputes) losses. Receivables are written off when collection efforts are exhausted and future recovery is doubtful. The Partnership includes an allowance forcurrent expected credit losses ("CECL") on its financial assets based on the loss-rate method. NRP assesses the likelihood of collection of its receivables utilizinghistorical loss rates, current market conditions, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individualcustomers and properties. See Note 18. Credit Losses for more information. The total allowance related to accounts receivables included in accounts receivables, net onthe Partnership's Consolidated Balance Sheets was $5.4 million and $4.5 million at December 31, 2023 and 2022, respectively. The total allowance related to short-termnotes receivables included in other current assets, net on the Partnership's Consolidated Balance Sheets was $0.3 million and $0.0 million at December 31, 2023 and 2022,respectively. The total allowance related to the Partnership's long-term financing receivable included in long-term contract receivable, net on the Consolidated BalanceSheets was $0.9 million and $1.0 million at December 31, 2023 and 2022, respectively. The Partnership recorded bad debt expense of $2.2 million, $1.1 million and$2.6 million included in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income for the year ended December 31, 2023, 2022 and2021, respectively. Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregatesmineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimatedeconomic tonnage therein. Intangible Assets The Partnership’s intangible assets consist of mineral royalty and transportation contracts that at acquisition were more favorable for the Partnership thanprevailing market rates, known as above-market contracts. The estimated fair value of the above-market rate contracts are determined based on the present value offuture cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis by asset based upon minerals minedor transported in relation to the net book value of the intangible asset and estimated economic tonnage expected to be mined or transported during the above-marketcontract term. Asset Impairment The Partnership has developed procedures to evaluate its long-lived assets, including intangible assets, for possible impairment periodically or whenever eventsor changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific eventssuch as a reduction in economically recoverable tons or production ceasing on a property for an extended period. This analysis is based on historic, current and futureperformance and considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows fromits use and disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usually determined based upon thepresent value of the projected future cash flows compared to the asset's net book value. The Partnership believes its estimates of cash flows and discount rates areconsistent with those of principal market participants. The Partnership evaluates its equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carryingvalue of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares theestimated fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the estimated fair value is lessthan 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 isrecognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices (Level 1), or upon the presentvalue of expected cash flows using discount rates believed to be consistent with those used by principal market participants (Level 3), plus market analysis ofcomparable assets owned by the investee, if appropriate (Level 3). Accrued Liabilities Included in accrued liabilities on the Partnership's Consolidated Balance Sheets at December 31, 2023 were $10.3 million of accrued employee costs and $2.7 millionof accrued property taxes. These amounts were $9.5 million and $2.4 million of accrued employee costs and accrued property taxes, respectively, at December 31, 2022. 52Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Revenue Recognition Mineral Rights Segment Revenues Royalty-based leases. Approximately two-thirds of the Partnership's royalty-based leases have initial terms of five to 40 years, with substantially all lesseeshaving the option to extend the lease for additional terms. For these types of leases, the lessees generally make payments to NRP based on the greater of a percentage ofthe gross sales price or a fixed price per ton of mineral mined and sold. Most of NRP’s coal and aggregates royalty leases require the lessee to pay quarterly or annualminimum amounts, either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally rangefrom three to five years. The Partnership has defined its coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell its coal or aggregatesover the lease term. NRP then evaluated the likelihood that consideration it expected to receive from its lessees resulting from production would exceed considerationexpected to be received from minimum payments over the lease term. As a result of this evaluation, revenue recognition from the Partnership's royalty-based leases is based on either production or minimum payments as follows:•Production Leases: Leases for which the Partnership expects that consideration from production will be greater than consideration from minimums over the leaseterm. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized asroyalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, NRP recognizes breakagerevenue from minimums when NRP determines that recoupment is remote. This breakage revenue is included in production lease minimum revenues.•Minimum Leases: Leases for which the Partnership expects that consideration from minimums will be greater than consideration from production over the leaseterm. Revenue for these leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues. This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease. Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of volume of hydrocarbons sold bylessees and the corresponding revenues from those sales. Also, included within oil and gas royalty revenues are lease bonus payments, which are generally paid uponthe execution of a lease. The Partnership also has overriding royalty revenue interests in certain coal and aggregates mineral rights. Revenue from these interests isrecognized over time based on when the coal is sold. Carbon neutral initiatives. Revenues related to consideration for carbon neutral initiatives that are recognized at a point in time upon satisfaction of NRP'sperformance obligation. Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property owned by the Partnership that is recognized over time astransportation across the property occurs. Other revenues. Other revenues consist primarily of rental payments and surface damage fees related to certain land owned by the Partnership and are recognizedstraight-line over time as it is earned. Other revenues also include property tax revenues. The majority of property taxes paid on the Partnership's properties arereimbursable by the lessee and are recognized on a gross basis over time which reflects the reimbursement of property taxes by the lessee. Property taxes paid by NRPare included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income. Transportation and processing services revenues. The Partnership owns transportation and processing infrastructure that is leased to third parties for throughputfees. Revenue is recognized over time based on the coal tons transported over the beltlines or processed through the facilities. Contract Modifications Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A majority of the Partnership's contractmodifications pertain to its coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices orminimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease willbe deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimumswill be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within royalty andother mineral rights revenues on the Consolidated Statements of Comprehensive Income while modifications in royalty rates and minimums will be recognizedprospectively in accordance with the above lease classification. Contract Assets and Liabilities from Contracts with Customers Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes unconditional. Receivables arerecognized when the minimums are contractually owed, production occurs or minimums accrued for based on the passage of time. Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time. The current portion of deferred revenuerelates to deferred revenue on minimum leases and lease amendment fees that are to be recognized as revenue on a straight-line basis over the next twelve months. Thelong-term portion of deferred revenue relates to deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-linebasis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as coal royalty revenues from itsproduction leases over the next twelve months, the Partnership is unable to estimate the current portion of deferred revenue. 53Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Equity in Earnings of Sisecam Wyoming The Partnership accounts for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercisesignificant influence over, but not control of, an investee. The Partnership's 49% investment in Sisecam Wyoming is accounted for using this method. Under the equitymethod of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or lossesand distributions. The basis difference between the investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortizedover its estimated useful life. The carrying value in Sisecam Wyoming is recognized in equity in unconsolidated investment on the Partnership's Consolidated BalanceSheets. The Partnership's adjusted share of the earnings or losses of Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings ofSisecam Wyoming on the Consolidated Statements of Comprehensive Income. The Partnership decreases its investment for its proportional share of distributionsreceived from Sisecam Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are consideredreturns on investment and classified as operating cash inflows unless the cumulative distributions received exceed the Partnership's cumulative equity in earnings. Theexcess of cumulative distributions received over the Partnership's cumulative equity in earnings are considered returns of investment and classified as investing cashinflows. Property Taxes The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing thePartnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in operating and maintenance expenses and inroyalty and other mineral rights revenues, respectively, on the Consolidated Statements of Comprehensive Income. Unit-Based Compensation The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units. The Partnership's service and performance-basedawards are valued using the closing price of NRP's units as of the grant date while the Partnership's market-based awards are valued using a Monte Carlosimulation. Compensation cost is remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the serviceperiod, which is generally the vesting period. Forfeitures are recognized as they occur. Unit-based compensation expense for all awards is recognized in general andadministrative expenses and operating and maintenance expenses on the Consolidated Statements of Comprehensive Income. See Note 16. Unit-Based Compensationfor more information. Deferred Financing Costs Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s debt. These costs are amortized over the term of therespective line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's revolving credit facility are included in other long-term assets, net onthe Partnership's Consolidated Balance Sheets. Deferred financing costs related to the Partnership's note agreements are included as a direct deduction from thecarrying amount of the debt liability in current portion of long-term debt, net or long-term debt, net on the Partnership's Consolidated Balance Sheets. Income Taxes The Partnership is not subject to federal or material state income taxes as the unitholders are taxed individually on their allocable share of taxable income. Netincome for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis andfinancial reporting basis of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the unitholders could be changed if anadjustment in the Partnership’s income is ultimately sustained by the taxing authorities. Recently Adopted Accounting Standard On January 1, 2023, NRP adopted Accounting Standards Update ("ASU") 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) andDerivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06)”. The ASU includes targeted improvements to earnings per share, whichthe Partnership adopted on a modified retrospective basis. The adoption of this ASU did not have a material impact on the Partnership’s Consolidated FinancialStatements. See Note 6. Net Income Per Common Unit for the calculations of our basic and diluted net income per common unit. See Note 4. Class A ConvertiblePreferred Units and Warrants for disclosures related to our convertible preferred units and warrants. Recently Issued Accounting Standard In November 2023, the FASB issued ASU No. 2023-07—Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures ("ASU 2023-07").The amendments in ASU 2023-07 improve reportable segment disclosure requirements, primarily through enhanced disclosures about segment expenses. The guidanceis effective for annual and interim periods beginning after December 15, 2023 and will be adopted retrospectively to all prior periods presented in the financialstatements. NRP does not expect the adoption of ASU 2023-07 to have a material effect on its Consolidated Financial Statements. 54Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 3. Revenues from Contracts with Customers The following table represents the Partnership's Mineral Rights segment revenues by major source: For the Year Ended December 31, (In thousands) 2023 2022 2021 Coal royalty revenues $218,011 $226,956 $104,089 Production lease minimum revenues 3,322 5,854 14,269 Minimum lease straight-line revenues 19,389 18,792 20,564 Carbon neutral initiative revenues 2,969 8,600 13,790 Property tax revenues 6,219 5,878 6,028 Wheelage revenues 12,191 13,961 10,065 Coal overriding royalty revenues 2,175 3,434 4,367 Lease amendment revenues 3,070 3,201 4,696 Aggregates royalty revenues 2,876 3,299 1,889 Oil and gas royalty revenues 7,387 16,161 4,506 Other revenues 1,124 877 933 Royalty and other mineral rights revenues $278,733 $307,013 $185,196 Transportation and processing services revenues (1) 14,923 21,072 9,052 Total Mineral Rights segment revenues $293,656 $328,085 $194,248 (1)Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $12.4 million, $17.9 million and $5.4 million for theyear ended December 31, 2023, 2022 and 2021, respectively. The remaining transportation and processing services revenues of $2.5 million, $3.2 million and$3.6 million for the year ended December 31, 2023, 2022 and 2021, respectively, related to other NRP-owned infrastructure leased to and operated by third-partyoperators accounted for under other guidance. See Note 17. Financing Transaction for more information. The following table details the Partnership's Mineral Rights segment receivables and liabilities resulting from contracts with customers: December 31, (In thousands) 2023 2022 Receivables Accounts receivable, net $37,206 $39,004 Other current assets, net (1) 429 — Other long-term assets, net (2) — 75 Contract liabilities Current portion of deferred revenue $4,599 $6,256 Deferred revenue 38,356 40,181 (1)Other current assets, net includes short-term notes receivables from contracts with customers.(2)Other long-term assets, net includes long-term lease amendment fee receivables from contracts with customers. The following table shows the activity related to the Partnership's Mineral Rights segment deferred revenue: For the Year Ended December 31, (In thousands) 2023 2022 2021 Balance at beginning of period (current and non-current) $46,437 $61,862 $61,554 Increase due to minimums and lease amendment fees 17,526 19,073 19,842 Recognition of previously deferred revenue (21,008) (34,498) (19,534)Balance at end of period (current and non-current) $42,955 $46,437 $61,862 The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty and overriding royalty leases are asfollows as of December 31, 2023 (in thousands): Lease Term (1) Weighted AverageRemaining Years Annual MinimumPayments 0 - 5 years 1.8 $17,477 5 - 10 years 6.1 18,655 10+ years 12.0 25,779 Total 7.4 $61,911 (1)Lease term does not include renewal periods. 55Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 4. Class A Convertible Preferred Units and Warrants On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "preferred units") to certainentities controlled by funds affiliated with The Blackstone Group Inc. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset ManagementLP (collectively referred to as "GoldenTree") (together the "preferred purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000preferred units to the preferred purchasers at a price of $1,000 per preferred unit (the "per unit purchase price"), less a 2.5% structuring and origination fee. The preferredunits entitle the preferred purchasers to receive cumulative distributions at a rate of 12% of the purchase price per year, up to one half of which NRP may pay inadditional preferred units (such additional preferred units, the "PIK units"). The preferred units have a perpetual term, unless converted or redeemed as described below. NRP also issued two tranches of warrants (the "warrants") to purchase common units to the preferred purchasers (warrants to purchase 1.75 million common unitswith a strike price of $22.81 and warrants to purchase 2.25 million common units with a strike price of $34.00). The warrants may be exercised by the holders thereof atany time before the eighth anniversary of the closing date. Upon exercise of the warrants, NRP may, at its option, elect to settle the warrants in common units or cash,each on a net basis. After March 2, 2022 and prior to March 2, 2025, the holders of the preferred units may elect to convert up to 33% of the outstanding preferred units in any 12-month period into common units if the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to datenotice is provided is greater than $51.00. In such case, the number of common units to be issued upon conversion would be equal to the per unit purchase price plus thevalue of any accrued and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior to the notice ofconversion. Rather than have the preferred units convert to common units in accordance with the provisions of this paragraph, NRP would have the option to elect toredeem the preferred units proposed to be converted for cash at a price equal to the per unit purchase price plus the value of any accrued and unpaid distributions. On or after March 2, 2025, the holders of the preferred units may elect to convert the preferred units to common units at a conversion rate equal to the LiquidationValue divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. The “liquidation value” will bean amount equal to the greater of: (1) (a) the per unit purchase price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021,1.70 and (iii) on or after March 2, 2021, 1.85, less (b)(i) all preferred unit distributions previously made by NRP and (ii) all cash payments previously made in respect ofredemption of any PIK units; and (2) the per unit purchase price plus the value of all accrued and unpaid distributions. To the extent the holders of the preferred units have not elected to convert their preferred units before March 2, 2029, NRP has the right to force conversion of thepreferred units at a price equal to the liquidation value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to thenotice of conversion. In addition, NRP has the ability to redeem at any time (subject to compliance with its debt agreements) all or any portion of the preferred units and any outstandingPIK units for cash. The redemption price for each outstanding PIK unit is $1,000 plus the value of any accrued and unpaid distributions per PIK unit. The redemptionprice for each preferred unit is the liquidation value divided by the number of outstanding preferred units. The preferred units are redeemable at the option of thepreferred purchasers only upon a change in control. The terms of the preferred units contain certain restrictions on NRP's ability to pay distributions on its common units. To the extent that either (i) NRP'sconsolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership Agreement dated March 2, 2017 (the "Restated PartnershipAgreement"), is greater than 3.25x, or (ii) the ratio of NRP's Distributable Cash Flow (as defined in the Restated Partnership Agreement) to cash distributions made orproposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), NRP may not increase the quarterly distributionabove $0.45 per quarter without the approval of the holders of a majority of the outstanding preferred units. In addition, if at any time after January 1, 2022, any PIK unitsare outstanding, NRP may not make distributions on its common units until it has redeemed all PIK units for cash. The holders of the preferred units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rightswith respect to changes of the terms of the preferred units. In addition, pursuant to the Restated Partnership Agreement, Blackstone had certain approval rights overcertain matters as identified in the Restated Partnership Agreement. GoldenTree has limited approval rights that expanded when Blackstone's ownership fell below theminimum preferred unit threshold (as defined below). These approval rights are not transferrable without NRP's consent and terminate at such time that Blackstone(together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of preferred units issued on theclosing date, together with all PIK units that have been issued but not redeemed (the "minimum preferred unit threshold"). At the closing, pursuant to the Board Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights, and Blackstoneappointed one director and one observer to the Board of Directors. However, in 2023, we repurchased all of Blackstone's preferred units, which were subsequentlyretired and no longer remain outstanding, and all rights of Blackstone related thereto ceased as a result. In connection with the repurchase, Blackstone's board designeeresigned from the Board of Directors. GoldenTree did not exercise its one-time option pursuant to the Board Rights Agreement to appoint either a director or an observerto the Board of Directors within 30 days of receipt of notice that Blackstone (and their affiliates) no longer own the Minimum Preferred Unit Threshold and GoldenTreeno longer has the right to appoint either a director or an observer to the Board of Directors. NRP also entered into a registration rights agreement (the "preferred unit and warrant registration rights agreement") with the preferred purchasers, pursuant towhich NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the warrants and to cause such registrationstatement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable uponconversion of the preferred units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90days following the first issuance of any common units upon conversion of preferred units. In addition, the preferred unit and warrant registration rights agreement givesthe preferred purchasers piggyback registration and demand underwritten offering rights under certain circumstances. The shelf registration statement to register thecommon units issuable upon exercise of the warrants became effective on April 20, 2017. The shelf registration statement to register the common units issuable uponexercise of the preferred units became effective on February 11, 2022. 56Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Accounting for the Preferred Units and Warrants Classification The preferred units are accounted for as temporary equity on NRP's Consolidated Balance Sheets due to certain contingent redemption rights that may beexercised at the election of preferred purchasers. The warrants are accounted for as equity on NRP's Consolidated Balance Sheets. Initial Measurement The net transaction price was allocated to the preferred units and warrants based on their relative fair values at inception date. NRP allocated the transactionissuance costs to the preferred units and warrants primarily on a pro-rata basis based on their relative inception date allocated values. Subsequent Measurement Preferred Units Subsequent adjustment of the preferred units will not occur until NRP has determined that the conversion or redemption of all or a portion of the preferred units isprobable of occurring. Once conversion or redemption becomes probable, the carrying amount of the preferred units will be accreted to their redemption value over theperiod from the date conversion or redemption becomes probable of occurring to the date the preferred units can first be converted or redeemed. In 2023, the Partnership received notices from holders of the preferred units exercising their right to either convert or redeem, at the election of NRP, an aggregateof 83,333 preferred units. The Partnership chose to redeem the preferred units for $83.3 million in cash rather than converting them into common units. In 2023, thePartnership also executed negotiated transactions with holders of the preferred units pursuant to which it repurchased and retired an aggregate of 95,001 preferred unitsfor $95.0 million in cash. Of the originally issued 250,000 preferred units, 71,666 preferred units remain outstanding as of December 31, 2023. Following these redemptionsand repurchases, the subject preferred units were retired and no longer remain outstanding, and Blackstone ceased to own any preferred units. All rights of Blackstonerelated to its ownership of preferred units, including Blackstone's right to appoint a board designee have ceased. Activity related to the preferred units is as follows: Units Financial (In thousands, except unit data) Outstanding Position Balance at December 31, 2020 253,750 $168,337 Distribution paid-in-kind 15,571 15,571 Balance at December 31, 2021 269,321 $183,908 Redemption of preferred units paid-in-kind (19,321) (19,321)Balance at December 31, 2022 250,000 $164,587 Redemption of preferred units (178,334) (117,406)Balance at December 31, 2023 71,666 $47,181 57Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Warrants Subsequent adjustment of the warrants will not occur until the warrants are exercised, at which time, NRP may, at its option, elect to settle the warrants in commonunits or cash, each on a net basis. The net basis will be equal to the difference between the Partnership's common unit price and the strike price of the warrant. Oncewarrant exercise occurs, the difference between the carrying amount of the warrants and the net settlement amount will be allocated on a pro-rata basis to the commonunitholders and general partner. In 2023, the Partnership negotiated transactions with holders of the Partnership's warrants pursuant to which the Partnership repurchased and retired an aggregateof 752,500 warrants with a strike price of $22.81 and 710,000 warrants with a strike price of $34.00 for approximately $56.1 million in cash. As of December 31, 2023,1,540,000 warrants with a strike price of $34.00 remained outstanding. As of December 31, 2022, 3,002,500 warrants remained outstanding, which included warrants topurchase 752,500 common units at a strike price of $22.81 and warrants to purchase 2,250,00 common units at a strike price of $34.00. These warrants had a $23.1 millionand $48.0 million carrying value included in warrant holders' interest within partners' capital on the Partnership's Consolidated Balance Sheets at December 31, 2023and December 31, 2022, respectively. On November 10, 2021 (the "exercise date"), Blackstone exercised all of its 997,500 warrants with a strike price of $22.81 and NRP settled the warrants in cash on anet basis. NRP delivered the net cash settlement amount of $9.2 million. The 15-day VWAP ending on the business day prior to the exercise date was $32.02. Activity related to the warrants is as follows: Warrants Financial (In thousands, except warrant data) Outstanding Position Balance at December 31, 2020 4,000,000 $66,816 Warrant settlement (997,500) (18,852)Balance at December 31, 2021 and 2022 3,002,500 $47,964 Warrant settlement (1,462,500) (24,869)Balance at December 31, 2023 1,540,000 $23,095 On January 29, 2024 (the "January 2024 exercise date"), holders of the Partnership's warrants exercised 462,165 warrants at a strike price of $34.00. The Partnershipsettled the warrants on a net basis with $10.0 million in cash and 198,767 common units. The 15-day VWAP ending on the business day prior to the January 2024 exercisedate was $97.62. On February 7, 2024 (the "February 7, 2024 exercise date"), holders of the Partnership's warrants exercised 128,750 warrants at a strike price of $34.00.The Partnership settled the warrants on a net basis with $8.0 million in cash. The 15-day VWAP ending on the business day prior to the February 7, 2024 exercise datewas $96.29. On February 8, 2024 (the "February 8, 2024 exercise date"), holders of the Partnership's warrants exercised 128,750 warrants at a strike price of $34.00. The 15-day VWAP ending on the business day prior to the February 8, 2024 exercise date was $95.63. The Partnership settled these warrants on a net basis with $7.9 million incash. On February 14, 2024 (the "February 14, 2024 exercise date"), holders of the Partnership's warrants exercised 500,000 warrants at a strike price of $34.00. The 15-dayVWAP ending on the business day prior to the February 14, 2024 exercise date was $93.47. The Partnership settled these warrants on a net basis with $29.7 million incash. Following these transactions, of the originally issued 4,000,000 warrants, 320,335 warrants with a strike price of $34.00 remain outstanding. As a result of thesesettlements, warrant holders' interest on the Partnership's Statement of Partners' Capital decreased by $18.3 million during the first quarter of 2024. Certain embedded features within the preferred unit and warrant purchase agreement are accounted for at fair value and are remeasured each quarter. See Note 12.Fair Value Measurements for further information regarding valuation of these embedded derivatives. 58Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 5. Common and Preferred Unit Distributions The Partnership makes distributions to common and preferred unitholders on a quarterly basis, subject to approval by the Board of Directors. NRP recognizes bothcommon unit and preferred unit distributions on the date the distribution is declared. Distributions made on the common units and the general partner's general partner ("GP") interest are made on a pro-rata basis in accordance with their relativepercentage interests in the Partnership. The general partner is entitled to receive 2% of such distributions. Income available to common unitholders and the general partner is adjusted by preferred unit distributions that accumulated during the period. NRP adjusted netincome available to common unitholders and the general partner by $16.7 million, $30.0 million and $31.6 million during the year ended December 31, 2023, 2022 and 2021,respectively as a result of accumulated preferred unit distributions earned during the period. Income available to common unitholders and the general partner is alsoreduced by the difference between the fair value of the consideration paid upon redemption and the carrying value of the preferred units. As such, NRP reduced netincome available to common unitholders and the general partner by $60.9 million during the year ended December 31, 2023. The following table shows the distributions declared and paid to common and preferred unitholders during the year ended December 31, 2023, 2022 and 2021,respectively: Cash Distributions Paid-in-kindDistributions Common Units Preferred Units Total Total Total Distribution Distribution(1) Distribution Distribution Distribution Date Paid Period Covered by Distribution per Unit (In thousands) per Unit (In thousands) (In units) 2023 February October 1 - December 31, 2022 $0.75 $9,571 $30.00 $7,500 — February (2) January 1 - February 8, 2023 — — 12.33 586 — March (3) Special Distribution 2.43 31,329 — — — May January 1 - March 31, 2023 0.75 9,669 30.00 6,075 — May (4) April 1 - May 5, 2023 — — 11.33 406 — June (5) April 1 - June 2, 2023 — — 20.33 915 — August April 1 - June 30, 2023 0.75 9,669 30.00 3,650 — August (6) June 30 - August 8, 2023 — — 12.33 432 — September (7) June 30 - September 12, 2023 — — 23.67 355 — November July 1 - September 30, 2023 0.75 9,670 30.00 2,150 — 2022 February October 1 - December 31, 2021 $0.45 $5,672 $30.00 $7,500 — February (8) January 1 - February 8, 2022 — — 13.35 258 — May January 1 - March 31, 2022 0.75 9,570 30.00 7,500 — August April 1 - June 30, 2022 0.75 9,571 30.00 7,500 — November July 1 - September 30, 2022 0.75 9,571 30.00 7,500 — 2021 February October 1 - December 31, 2020 $0.45 $5,630 $15.00 $3,806 3,806 May January 1 - March 31, 2021 0.45 5,672 15.00 3,864 3,864 August April 1 - June 30, 2021 0.45 5,671 15.00 3,921 3,921 November July 1 - September 30, 2021 0.45 5,672 15.00 3,980 3,980 (1)Totals include the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest.(2)Relates to accrued distribution paid upon the redemption of 47,499 preferred units in February 2023.(3)Special distribution was made to help cover unitholder tax liabilities associated with owning NRP's common units during 2022.(4)Relates to accrued distribution paid upon the redemption of 35,834 preferred units in May 2023.(5)Relates to accrued distribution paid upon the redemption of 45,000 preferred units in June 2023.(6)Relates to accrued distribution paid upon the redemption of 35,000 preferred units in August 2023.(7)Relates to accrued distribution paid upon the redemption of 15,001 preferred units in September 2023.(8)Relates to accrued distribution paid upon the redemption of 19,321 preferred units paid-in-kind in February 2022. 59Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 6. Net Income Per Common Unit Basic net income per common unit is computed by dividing net income, after considering income attributable to preferred unitholders, the difference between thefair value of the consideration paid upon redemption and the carrying value of the preferred units, and the general partner’s general partner interest, by the weightedaverage number of common units outstanding. Diluted net income per common unit includes the effect of NRP's preferred units, warrants, and unvested unit-basedawards if the inclusion of these items is dilutive. The dilutive effect of the preferred units is calculated using the if-converted method. Under the if-converted method, the preferred units are assumed to beconverted at the beginning of the period, and the resulting common units are included in the denominator of the diluted net income per unit calculation for the periodbeing presented. Distributions declared in the period and undeclared distributions on the preferred units that accumulated during the period are added back to thenumerator for purposes of the if-converted calculation. The calculation of diluted net income per common unit for the year ended December 31, 2023 includes theassumed conversion of the remaining preferred units while it does not include the assumed conversion of the preferred units that were redeemed during the year endedDecember 31, 2023 as the inclusion of these units would be anti-dilutive. The calculation of diluted net income per common unit for the year ended December 31, 2022and 2021 includes the assumed conversion of the preferred units. The dilutive effect of the warrants is calculated using the treasury stock method, which assumes that the proceeds from the exercise of these instruments are usedto purchase common units at the average market price for the period. The calculation of diluted net income per common unit for the year ended December 31,2023 includes the net settlement of warrants to purchase 1,540,000 common units with a strike price of $34.00. The calculation of diluted net income per common unit forthe year ended December 31, 2022 includes the net settlement of warrants to purchase 752,500 common units with a strike price of $22.81 and the net settlement ofwarrants to purchase 2,250,000 common units with a strike price of $34.00. The calculation of diluted net income per common unit for the year ended December 31,2021 includes the net settlement of warrants to purchase 752,500 common units with a strike price of $22.81 but does not include the net settlement of warrants topurchase 2,250,000 common units with a strike price of $34.00 because the impact would have been anti-dilutive. The following table reconciles the numerators and denominators of the basic and diluted net income per common unit computations and calculates basic anddiluted net income per common unit: For the Year Ended December 31, (In thousands, except per unit data) 2023 2022 2021 Basic net income per common unit Net income attributable to common unitholders $196,771 $233,722 $75,747 Weighted average common units—basic 12,619 12,484 12,337 Basic net income per common unit $15.59 $18.72 $6.14 Diluted net income per common unit Weighted average common units—basic 12,619 12,484 12,337 Plus: dilutive effect of preferred units 2,059 6,176 9,604 Plus: dilutive effect of warrants 1,202 783 74 Plus: dilutive effect of unvested unit-based awards 216 210 178 Weighted average common units—diluted 16,096 19,653 22,193 Net income $278,435 $268,492 $108,902 Less: income attributable to preferred unitholders (2,694) — — Less: redemption of preferred units (60,929) — — Diluted net income attributable to common unitholders and the general partner $214,812 $268,492 $108,902 Less: diluted net income attributable to the general partner (4,296) (5,370) (2,178)Diluted net income attributable to common unitholders $210,516 $263,122 $106,724 Diluted net income per common unit $13.08 $13.39 $4.81 60Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 7. Segment Information The Partnership's segments are strategic business units that offer distinct products and services to different customers in different geographies within the U.S.and that are managed accordingly. NRP has the following two operating segments: Mineral Rights—consists of mineral interests and other subsurface rights across the United States. NRP's ownership provides critical inputs for themanufacturing of steel, electricity and basic building materials, as well as opportunities for carbon sequestration and renewable energy. The Partnership is working tostrategically redefine its business as a key player in the transitional energy economy in the years to come. Soda Ash—consists of the Partnership's 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining operation and soda ash refinery in the GreenRiver Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicalsindustries. Direct segment costs and certain other costs incurred at the corporate level that are identifiable and that benefit the Partnership's segments are allocated to theoperating segments accordingly. These allocated costs generally include salaries and benefits, insurance, property taxes, legal, royalty, information technology andshared facilities services and are included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income. Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest andfinancing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment andare included in general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income. The following table summarizes certain financial information for each of the Partnership's business segments: Operating Segments (In thousands) Mineral Rights Soda Ash Corporate andFinancing Total For the Year Ended December 31, 2023 Revenues $293,656 $73,397 $— $367,053 Gain on asset sales and disposals 2,956 — — 2,956 Operating and maintenance expenses 32,058 257 — 32,315 Depreciation, depletion and amortization 18,471 — 18 18,489 General and administrative expenses — — 26,111 26,111 Asset impairments 556 — — 556 Other expenses, net — — 14,103 14,103 Net income (loss) 245,527 73,140 (40,232) 278,435 As of December 31, 2023 Total assets $516,844 $276,549 $4,483 $797,876 For the Year Ended December 31, 2022 Revenues $328,085 $59,795 $— $387,880 Gain on asset sales and disposals 1,082 — — 1,082 Operating and maintenance expenses 34,743 160 — 34,903 Depreciation, depletion and amortization 22,519 — — 22,519 General and administrative expenses — — 21,852 21,852 Asset impairments 4,457 — — 4,457 Other expenses, net — — 36,739 36,739 Net income (loss) 267,448 59,635 (58,591) 268,492 As of December 31, 2022 Total assets $566,615 $306,470 $4,046 $877,131 For the Year Ended December 31, 2021 Revenues $194,248 $21,871 $— $216,119 Gain on asset sales and disposals 245 — — 245 Operating and maintenance expenses 26,880 169 — 27,049 Depreciation, depletion and amortization 19,075 — — 19,075 General and administrative expenses — — 17,360 17,360 Asset impairments 5,102 — — 5,102 Other expenses, net 24 — 38,852 38,876 Net income (loss) 143,412 21,702 (56,212) 108,902 61Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 8. Equity Investment The Partnership accounts for its 49% investment in Sisecam Wyoming using the equity method of accounting. Activity related to this investment is as follows: For the Year Ended December 31, (In thousands) 2023 2022 2021 Balance at beginning of period $306,470 $276,004 $262,514 Income allocation to NRP’s equity interests (1) 78,179 64,712 26,979 Amortization of basis difference (4,783) (4,917) (5,108)Other comprehensive income (loss) (21,839) 15,506 2,889 Distributions (81,478) (44,835) (11,270)Balance at end of period $276,549 $306,470 $276,004 (1)Amounts reclassified into income out of accumulated other comprehensive loss were $(17.9) million, $(6.8) million and $0.0 million for the year ended December 31,2023, 2022 and 2021, respectively. The difference between the amount at which the investment in Sisecam Wyoming is carried and the amount of underlying equity in Sisecam Wyoming's net assetswas $116.6 million and $121.3 million as of December 31, 2023 and 2022, respectively. This excess basis relates to property, plant and equipment and right to mine assets.The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over 27 years. The excess basisdifference that relates to right to mine assets is being amortized into income using the units of production method. The following table represents summarized financial information for Sisecam Wyoming as derived from their respective financial statements for the years endedDecember 31, 2023, 2022, and 2021: For the Year Ended December 31, (In thousands) 2023 2022 2021 Net sales $773,590 $720,120 $540,139 Gross profit 187,929 162,575 80,550 Net income 159,549 132,065 55,059 The financial position of Sisecam Wyoming is summarized as follows: December 31, (In thousands) 2023 2022 Current assets $253,754 $340,437 Noncurrent assets 284,131 292,915 Current liabilities 91,853 111,258 Noncurrent liabilities 119,533 144,290 62Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 9. Mineral Rights, Net The Partnership’s mineral rights consist of the following: December 31, 2023 2022 (In thousands) Carrying Value AccumulatedDepletion Net Book Value Carrying Value AccumulatedDepletion Net Book Value Coal properties $661,256 $(285,470) $375,786 $661,812 $(269,037) $392,775 Aggregates properties 8,655 (3,761) 4,894 8,655 (3,410) 5,245 Oil and gas royalty properties 12,354 (10,082) 2,272 12,354 (9,600) 2,754 Other 13,143 (1,612) 11,531 13,150 (1,612) 11,538 Total mineral rights, net $695,408 $(300,925) $394,483 $695,971 $(283,659) $412,312 Depletion expense related to the Partnership’s mineral rights is included in depreciation, depletion and amortization on its Consolidated Statements ofComprehensive Income and totaled $17.3 million, $20.9 million and $17.6 million for the year ended December 31, 2023, 2022 and 2021, respectively. Impairment of Mineral Rights During the years ended December 31, 2023, 2022 and 2021, the Partnership identified facts and circumstances that indicated that the carrying value of certain of itsmineral rights exceed future cash flows from those assets and recorded non-cash impairment expense included in asset impairments on the Consolidated Statements ofComprehensive Income as follows: For the Year Ended December 31, (In thousands) 2023 2022 2021 Coal properties (1) $556 $4,365 $5,015 Aggregates properties (2) — 92 87 Total $556 $4,457 $5,102 (1)The Partnership recorded $0.6 million of impairment expense during the year ended December 31, 2023. The Partnership recorded $4.4 million of impairment expenseduring the year ended December 31, 2022 primarily related to assets whose undiscounted future net cash flows were less than their net book values. Of this amount,$2.6 million of impairment expense related to an asset with $4.3 million of net book value, resulting in a fair value of $1.7 million at December 31, 2022. The fair valueof the impaired asset at December 31, 2022 was calculated using a discount rate of 15%. The Partnership recorded $5.0 million of impairment expense during the yearended December 31, 2021 primarily related to the full impairment of an asset resulting from a lease termination. NRP compared the net book value of its coalproperties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted future cash flows, the Partnership recorded animpairment for the excess of the net book value over fair value. A discounted cash flow model was used to estimate the level 3 fair value. Significant inputs used todetermine fair value include estimates of future cash flows from coal sales and minimum payments, discount rate and useful economic life. Estimated cash flows arethe product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization ofcash flows.(2)The Partnership recorded $0.1 million of aggregates royalty property impairments during the years ended December 31, 2022 and 2021. NRP compared the net bookvalue of its aggregates properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted cash flows, the Partnershiprecorded an impairment for the excess of the net book value over fair value. A discounted cash flow model was used to estimate the level 3 fair value. Significantinputs used to determine fair value include estimates of future cash flows from aggregates sales and minimum payments, discount rate and useful economic life.Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related tothe future realization of cash flows. 63Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 10. Intangible Assets, Net The Partnership's intangible assets consist of above-market coal royalty and related transportation contracts with subsidiaries of Foresight Energy ResourcesLLC ("Foresight") pursuant to which the Partnership receives royalty payments for coal sales and throughput fees for the transportation and processing of coal. ThePartnership's intangible assets included on its Consolidated Balance Sheets are as follows:Partnership's intangible assets included on its Consolidated Balance Sheets are as follows: December 31, (In thousands) 2023 2022 Intangible assets at cost $51,353 $51,353 Less: accumulated amortization (37,671) (36,640)Total intangible assets, net $13,682 $14,713 Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of Comprehensive Income was$1.0 million, $1.4 million and $1.3 million for the year ended December 31, 2023, 2022 and 2021, respectively. The estimates of amortization expense for the years ended December 31, as indicated below, are based on current lessee mining plans and are subject to revisionas those plans change in future periods. (In thousands) EstimatedAmortizationExpense 2024 $884 2025 813 2026 753 2027 720 2028 480 64Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 11. Debt, Net The Partnership's debt consists of the following: December 31, (In thousands) 2023 2022 Opco Credit Facility $95,834 $70,000 Opco Senior Notes 5.55% with semi-annual interest payments in June and December, with annual principal payments in June, dueJune 2023 $— $2,366 4.73% with semi-annual interest payments in June and December, with annual principal payments in December,due December 2023 — 6,004 5.82% with semi-annual interest payments in March and September, with annual principal payments in March,due March 2024 12,685 25,368 8.92% with semi-annual interest payments in March and September, with annual principal payments in March,due March 2024 4,012 8,023 5.03% with semi-annual interest payments in June and December, with annual principal payments in December,due December 2026 34,262 45,683 5.18% with semi-annual interest payments in June and December, with annual principal payments in December,due December 2026 8,732 11,643 Total Opco Senior Notes $59,691 $99,087 Total debt at face value $155,525 $169,087 Net unamortized debt issuance costs (467) (806)Total debt, net $155,058 $168,281 Less: current portion of long-term debt (30,785) (39,076)Total long-term debt, net $124,273 $129,205 NRP LP Debt 2025 Senior Notes In 2022, NRP redeemed all $300 million of its 2025 Senior Notes. Included in loss on extinguishment of debt on the Partnership's Consolidated Statements ofComprehensive Income for the year ended December 31, 2022, are $7.2 million of call premium and fees and the write off of $3.1 million of debt issuance costs. The cashpaid for call premiums and fees is included in other items, net under cash used in financing activities on the Consolidated Statements of Cash Flows. The followingdescribes the terms of the 2025 Senior Notes prior to their redemption. The 2025 Senior Notes were issued under an Indenture dated as of April 29, 2019 (the "2025 Indenture"), bore interest at 9.125% per year and would have maturedon June 30, 2025. Interest was payable semi-annually on June 30 and December 30. NRP had the option to redeem the 2025 Senior Notes, in whole or in part, at any timeon or after October 30, 2021, at the redemption prices (expressed as percentages of principal amount) of 104.563% for the 12-month period beginning October 30,2021, 102.281% for the 12-month period beginning October 30, 2022, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the dateof redemption. In the event of a change of control, as defined in the 2025 Indenture, the holders of the 2025 Senior Notes may have required us to purchase their 2025Senior Notes at a purchase price equal to 101% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest, if any. The 2025 Senior Notes wereissued at par. The 2025 Senior Notes were the senior unsecured obligations of NRP. The 2025 Senior Notes ranked equal in right of payment to all existing and future seniorunsecured debt of NRP and senior in right of payment to any of NRP's subordinated debt. The 2025 Senior Notes were effectively subordinated in right of payment to allfuture secured debt of NRP to the extent of the value of the collateral securing such indebtedness was structurally subordinated in right of payment to all existing andfuture debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiariesguaranteed the 2025 Senior Notes. 65Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Opco Debt All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries, other thanBRP LLC and NRP Trona LLC. As of December 31, 2023 and 2022, Opco was in compliance with the terms of the financial covenants contained in its debt agreements. Opco Credit Facility In May 2023, the Partnership entered into the Sixth Amendment (the "Sixth Amendment") to the Opco Credit Facility (the "Opco Credit Facility"). TheSixth Amendment extended the term of the Opco Credit Facility until August 2027. Lender commitments under the Opco Credit Facility increased from $130.0 million to$155.0 million, with the ability to expand such commitments to $200.0 million with the addition of future commitments. The Sixth Amendment also includes modificationsto Opco's ability to declare and make certain restricted payments. Indebtedness under the Opco Credit Facility bears interest, at Opco's option, at:•the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) SOFR plus 1%, in each case plus an applicable marginranging from 2.50% to 3.50%; or•a rate equal to SOFR plus an applicable margin ranging from 3.50% to 4.50%. During the year ended December 31, 2022, the Partnership borrowed $70.0 million under the Opco Credit Facility, resulting in $70.0 million in borrowingsoutstanding and $60.0 million of available borrowing capacity under the Opco Credit Facility as of December 31, 2022. During the year ended December 31, 2023 thePartnership borrowed $248.8 million and repaid $223.0 million, resulting in $95.8 million in borrowings outstanding and $59.2 of available borrowing capacity under theOpco Credit Facility as of December 31, 2023. The weighted average interest rate for the borrowings outstanding under the Opco Credit Facility for the year endedDecember 31, 2023 and 2022 were 8.70% and 7.17%, respectively. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rateof 0.50% per annum. Opco may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty. The Opco Credit Facility contains financial covenants requiring Opco to maintain:•A leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 3.0x; and•an interest coverage ratio of consolidated EBITDDA to consolidated interest expense and consolidated lease expense (in each case as defined in the Opco CreditFacility) of not less than 3.5 to 1.0. The Opco Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grantliens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability toacquire assets where Opco does not maintain certain levels of liquidity. In addition, Opco is required to use 75% of the net cash proceeds of certain non-ordinary courseasset sales to repay the Opco Credit Facility (without any corresponding commitment reduction) and use the remaining 25% of the net cash proceeds to offer to repayits Senior Notes on a pro-rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility also contains customary events of default, includingcross-defaults under Opco’s Senior Notes. The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $316.3 million and $326.4 million classified asmineral rights, net and other long-term assets, net and $26.3 million and $28.9 million classified as long-term contract receivable, net on the Partnership’s ConsolidatedBalance Sheets as of December 31, 2023 and 2022, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than BRPLLC and NRP Trona LLC (which owns a 49% non-controlling equity interest in Sisecam Wyoming), (2) the personal property and fixtures owned by Opco’s whollyowned subsidiaries, other than BRP LLC and NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, and (4) certain of Opco’s coal-relatedinfrastructure assets, including its long-term contract receivable as described in Note 17. Financing Transaction. In February 2024, the Partnership exercised its option under the Opco Credit Facility to increase the total aggregate commitment under the Opco Credit Facilitytwice, initially by $30.0 million from $155.0 million to $185.0 million and subsequently by $15.0 million from $185.0 million to $200.0 million. These increases in the totalaggregate commitment were made pursuant to an accordion feature of the Opco Credit Facility. In connection with the initial increase, a new lender joined the lendinggroup with a commitment of $30.0 million. The Opco Credit Facility otherwise continues to operate under its existing terms and conditions in all material respects. 66Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED Opco Senior Notes Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of December31, 2023 and 2022, the Opco Senior Notes had cumulative principal balances of $59.7 million and $99.1 million, respectively. Opco made mandatory principal payments onthe Opco Senior Notes of $39.4 million during the years ended December 31, 2023, 2022 and 2021. The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to:•maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four mostrecent quarters;•not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement);and•maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expenseand consolidated operating lease expense) at not less than 3.5 to 1.0. In addition, the Note Purchase Agreements include a covenant that provides that, in the event Opco or any of its subsidiaries is subject to any additional or morerestrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility and all renewals, amendments or restatementsthereof), such covenants shall be deemed to be incorporated by reference in the Note Purchase Agreements and the holders of the Notes shall receive the benefit ofsuch additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement. The 8.92% Opco Senior Notes also provides that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined inthe Note Purchase Agreements) 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 inthe 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.Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2023. In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepaymentoffers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount ofOpco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid. The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-wholepayment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of OpcoSenior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes. Consolidated Principal Payments The consolidated principal payments due are set forth below: (In thousands) Opco Senior Notes Opco Credit Facility Total 2024 $31,028 $— $31,028 2025 14,332 — 14,332 2026 14,331 — 14,331 2027 — 95,834 95,834 2028 — — — Thereafter — — — $59,691 $95,834 $155,525 67Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 12. Fair Value Measurements Fair Value of Financial Assets and Liabilities The Partnership’s financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The carrying amounts reported on theConsolidated Balance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. The Partnership uses available market data andvaluation methodologies to estimate the fair value of its debt and contract receivable. The following table shows the carrying value and estimated fair value of the Partnership's debt and contract receivable: December 31, 2023 2022 Carrying Estimated Carrying Estimated (In thousands) Fair Value Hierarchy Level Value Fair Value Value Fair Value Debt: Opco Senior Notes (1) 3 $59,224 $56,533 $98,281 $96,060 Opco Credit Facility (2) 3 95,834 95,384 70,000 70,000 Assets: Contract receivable, net (current and long-term) (3) 3 $28,946 $24,492 $31,371 $24,833 (1)The fair value of the Opco Senior Notes was estimated by management utilizing the present value replacement method incorporating the interest rate of the OpcoCredit Facility.(2)The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates andthe terms of the credit facility allow the Partnership to repay this debt at any time without penalty.(3)The fair value of the Partnership's contract receivable was determined based on the present value of future cash flow projections related to the underlying asset at adiscount rate of 15% at December 31, 2023 and 2022. NRP has embedded derivatives in the preferred units related to certain conversion options, redemption features and the change of control provision that areaccounted for separately from the preferred units as assets and liabilities at fair value on the Partnership's Consolidated Balance Sheets. Level 3 valuation of theembedded derivatives are based on numerous factors including the likelihood of the event occurring. The embedded derivatives are revalued quarterly and changes intheir fair value would be recorded in other expenses, net on the Partnership's Consolidated Statements of Comprehensive Income. The embedded derivatives had zerovalue as of December 31, 2023 and 2022. Fair Value of Non-Financial Assets The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregates properties at fair value on a nonrecurring basis. Referto Note 9. Mineral Rights, Net for additional disclosures related to the fair value associated with the impaired assets. 68Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 13. Related Party Transactions Affiliates of our General Partner The Partnership’s general partner does not receive any management fee or other compensation for its management of NRP. However, in accordance with thepartnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’sbehalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, providetheir services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to theiremployee services provided to NRP. These QMC and WPPLP employee management service costs are presented as operating and maintenance expenses and generaland administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income. NRP also reimburses overhead costs incurred by its affiliates,including Quintana Infrastructure Development ("QID"), to manage the Partnership's business. These overhead costs include certain rent, information technology,administration of employee benefits and other corporate services incurred by or on behalf of the Partnership’s general partner and its affiliates and are presented asoperating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income. Direct general and administrative expenses charged to the Partnership by QMC, WPPLP and QID are included on the Partnership's Consolidated Statement ofComprehensive Income as follows: For the Year Ended December 31, (In thousands) 2023 2022 2021 Operating and maintenance expenses $6,747 $6,694 $6,543 General and administrative expenses 5,408 4,864 4,611 The Partnership had accounts payable to QMC of $0.4 million on its Consolidated Balance Sheets at both December 31, 2023 and 2022 and $0.2 million and$1.0 million of accounts payable to WPPLP at December 31, 2023 and 2022, respectively. As a result of its office lease with WPPLP, the Partnership had a right-of-use asset and lease liability of $3.5 million included in other long-term assets, net andother non-current liabilities, respectively, on its Consolidated Balance Sheets at both December 31, 2023 and 2022. During the years ended December 31, 2023, 2022 and 2021, the Partnership recognized $5.1 million, $8.5 million and $3.3 million in operating and maintenanceexpenses, respectively, on its Consolidated Statements of Comprehensive Income related to an overriding royalty agreement with WPPLP. 69Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 14. Major Customers Revenues from customers that exceeded 10 percent of total revenues for any of the periods presented below are as follows: For the Year Ended December 31, 2023 2022 2021 (In thousands) Revenues Percent Revenues Percent Revenues Percent Alpha Metallurgical Resources, Inc. (1) $86,118 23% $102,352 26% $49,440 23%Foresight (1) (2) 60,495 16% 65,597 17% 37,366 17% (1)Revenues from Alpha Metallurgical Resources, Inc. and Foresight are included within the Partnership's Mineral Rights segment.(2)Revenues from Foresight in 2021 were fixed as a result of the lease amendment the Partnership entered into with Foresight pursuant to which Foresight agreed topay NRP fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreementsbetween the Partnership and Foresight. Revenues from Foresight in 2022 and 2023 represent traditional royalty and minimum payments. 15. Commitments and Contingencies Legal NRP is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannotbe predicted with certainty, Partnership management believes these ordinary course matters will not have a material effect on the Partnership’s financial position,liquidity or operations. Environmental Compliance The operations the Partnership’s lessees conduct on its properties, as well as the industrial minerals, aggregates and oil and gas operations in which thePartnership has interests, are subject to federal and state environmental laws and regulations. See "Items 1. and 2. Business and Properties—Regulation andEnvironmental Matters." As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on thesurface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, includingenvironmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially allof the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive thetermination of the lease. The Partnership makes regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests withthe lessees. The Partnership believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply withenvironmental laws and regulations will have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, noris aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31, 2023. The Partnership is notassociated with any material environmental contamination that may require remediation costs. However, the Partnership’s lessees are required to conduct reclamationwork on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, the Partnership is not responsible for the costsassociated with these reclamation operations. As a former owner of the working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities,including environmental liabilities, arising from uninsured and underinsured events during the period it was an owner. 70Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 16. Unit-Based Compensation 2017 Long-Term Incentive Plan In December 2017, the 2017 Long-Term Incentive Plan (the “2017 LTIP”) was approved and it became effective in January 2018. The 2017 LTIP authorizes a total of1,600,000 common units that are available for delivery by the Partnership pursuant to awards under the plan. The initial number of common units authorized for issuancepursuant to awards under the plan was 800,000 and in March 2022, an additional 800,000 units were authorized for issuance. The term is 10 years from the date ofapproval of the Board of Directors or, if earlier, the date the 2017 LTIP is terminated by the Board of Directors or the committee appointed by the Board of Directors toadminister the 2017 LTIP, or the date all available common units available have been delivered. Common units delivered pursuant to the 2017 LTIP will consist, in wholeor part, of (i) common units acquired in the open market, (ii) common units acquired from the Partnership (including newly issued units), any of our affiliates or any otherperson or (iii) any combination of the foregoing. Employees, consultants and non-employee directors of the Partnership, the general partner, GP LLC and their affiliates are generally eligible to receive awardsunder the 2017 LTIP. The 2017 LTIP provides for the issuance of a variety of equity-based grants, including grants of (i) options, (ii) unit appreciation rights, (iii)restricted units, (iv) phantom units, (v) cash awards, (vi) performance awards, (vii) distribution equivalent rights, and (viii) other unit-based awards. The plan isadministered by the Compensation, Nominating and Governance Committee ("CNG Committee") of the Board of Directors, which determines the terms and conditions ofawards granted under the 2017 LTIP. The Partnership recognizes forfeitures for any awards issued under this plan as they occur. Unit-Based Awards Unit-based awards under the 2017 LTIP are generally issued to certain employees and non-employee directors of the Partnership. Awards granted to employeeseither vest 3 years following the grant date or vest ratably over the 3 year period following the grant date. Awards granted to non-employee directors vest over a 1 yearperiod. Directors are given the option to take immediate issuance of the vested awards or defer such issuance until a later date. Upon deferral of issuance, such units willcontinue to accumulate distribution equivalent rights ("DERs") until issuance. In connection with the phantom unit awards, the CNG Committee also granted tandem DERs, which entitle the holders to receive distributions equal to thedistributions paid on the Partnership’s common units between the date the units are granted and the settlement date. The DERs are payable in cash upon vesting butmay be subject to forfeiture if the grantee ceases employment prior to vesting. During the year ended December 31, 2023, the Partnership granted service, performance and market-based awards under its 2017 Long-Term Incentive Plan andduring the years ended December 31, 2022 and 2021, the Partnership granted service-based awards. The Partnership's service and performance-based awards are valuedat the closing price of NRP's units as of the grant date while the Partnership's market-based awards are valued using a Monte Carlo simulation. The grant date fair valueof these awards granted during the year ended December 31, 2023, 2022 and 2021 were $16.0 million, which included a grant-date fair value of $2.8 million for the market-based awards valued using a Monte Carlo simulation, $7.9 million and $3.8 million, respectively. Total unit-based compensation expense associated with these awardswas $10.9 million, $5.8 million and $4.0 million for the year ended December 31, 2023, 2022 and 2021, respectively, and is included in general and administrative expensesand operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income. The unamortized cost associated with unvestedoutstanding awards as of December 31, 2023 is $13.3 million, which will be recognized over a weighted average period of 1.9 years. The unamortized cost associated withunvested outstanding awards as of December 31, 2022 was $6.3 million. A summary of the unit activity in the outstanding grants during 2023 is as follows: (In thousands) Common Units Weighted Average GrantDate Fair value perCommon Unit Outstanding grants at January 1, 2023 386 $28.96 Granted 281 $56.84 Fully vested and issued (184) $26.30 Outstanding at December 31, 2023 483 $46.21 71Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 17. Financing Transaction The Partnership owns rail loadout and associated infrastructure at the Sugar Camp mine in the Illinois Basin operated by a subsidiary of Foresight. Theinfrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight and is accounted for as a financing transaction (the "Sugar Camp lease"). The Sugar Camplease expires in 2032 with renewal options for up to 80 additional years. Minimum payments are $5.0 million per year through the end of the lease term. The $5.0 milliondue to the Partnership in 2021 was included in the fixed cash payments from Foresight resulting from contract modifications entered into during the second quarter of2020 as discussed in Note 14. Major Customers. The Partnership is also entitled to variable payments in the form of throughput fees determined based on the amount ofcoal transported and processed utilizing the Partnership's assets. In the event the Sugar Camp lease is renewed beyond 2032, payments become a fixed $10 thousand peryear for the remainder of the renewed term. 18. Credit Losses The Partnership is exposed to credit losses through the collection of its trade receivables resulting from contracts with customers and a long-term receivableresulting from a financing transaction with a customer. The Partnership records an allowance for current expected credit losses on these receivables based on the loss-rate method. NRP assessed the likelihood of collection of its receivables utilizing historical loss rates, current market conditions that included the estimated impact of theglobal COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers andproperties. Examples of these facts or circumstances include, but are not limited to, contract disputes or renegotiations with the customer and evaluation of short andlong-term economic viability of the contracted property. For its long-term contract receivable, management reverts to the historical loss experience immediately after thereasonable and supportable forecast period ends. As of December 31, 2023 and 2022, NRP recorded the following current expected credit loss (“CECL”) related to its receivables and long-term contract receivable: December 31, 2023 2022 (In thousands) Gross CECLAllowance Net Gross CECLAllowance Net Receivables $47,170 $(5,655) $41,515 $47,237 $(4,461) $42,776 Long-term contract receivable 27,265 (944) 26,321 29,984 (1,038) 28,946 Total $74,435 $(6,599) $67,836 $77,221 $(5,499) $71,722 NRP recorded $1.1 million, $1.1 million and $0.5 million in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income related tothe change in the CECL allowance during the year ended December 31, 2023, 2022 and 2021, respectively. NRP has procedures in place to monitor its ongoing credit exposure through timely review of counterparty balances against contract terms and due dates, accountand financing receivable reconciliations, bankruptcy monitoring, lessee audits and dispute resolution. The Partnership may employ legal counsel or collectionspecialists to pursue recovery of defaulted receivables. 72Table of Contents NATURAL RESOURCE PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED 19. Leases As of December 31, 2023, the Partnership had two operating leases for office buildings. On January 1, 2019, the Partnership entered into a new lease for the WestVirginia office building owned by WPPLP with a five-year base term and five additional five-year renewal options. Upon lease commencement and as of December 31,2023 and 2022, the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding leaseliability on its Consolidated Balance Sheets using the present value of the future lease payments over 30 years. On January 1, 2023, the Partnership entered into a newlease for an office building in Houston with an 11.4 year initial term and a two additional five-year renewal options. Upon lease commencement and as of December 31,2023, the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liabilityon its Consolidated Balance Sheets using the present value of the future lease payments over 21.4 years. The Partnership's right-of-use asset and lease liability includedwithin other long-term assets, net and other non-current liabilities, respectively, on its Consolidated Balance Sheets totaled $4.3 million and $3.5 million at December 31,2023 and 2022, respectively. During the years ended December 31, 2023, 2022 and 2021, the Partnership incurred total operating lease expenses of $0.6 million, $0.5 millionand $0.5 million included in both operating and maintenance expenses and general and administrative expenses on its Consolidated Statements of ComprehensiveIncome..The following table details the maturity analysis of the Partnership's operating lease liability and reconciles the undiscounted cash flows to the operating leaseliability included on its Consolidated Balance Sheet: Remaining Annual Lease Payments (In thousands) December 31, 2023 2024 $541 2025 601 2026 604 2027 607 2028 611 After 2028 12,040 Total lease payments (1) $15,004 Less: present value adjustment (2) (10,683)Total operating lease liability $4,321 (1)The remaining lease terms of the Partnership's two operating leases are 25 years and 20.4 years.(2)The present value of the operating lease liability on the Partnership's Consolidated Balance Sheets was calculated using a 13.5% discount rate on the 30-year leaseand a 13.4% discount rate on the 21.4 year lease. These rates represent the Partnership's estimated incremental borrowing rates under its two operating leases. Asthe Partnership's leases do not provide an implicit rate, the Partnership estimated the incremental borrowing rates at the time the leases were entered into by utilizingthe rate of the Partnership's secured debt and adjusting it for factors that reflect the profile of borrowing over the 30-year and 21.4-year expected lease terms,respectively. 73Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of theExchange Act) as of December 31, 2023. This evaluation was performed under the supervision and with the participation of our management, including the ChiefExecutive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officerand Chief Financial Officer concluded that these disclosure controls and procedures were effective as of December 31, 2023 at the reasonable assurance level inproducing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow fortimely decisions with regard to required disclosures. Management’s Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GPNatural Resource Partners LLC, our managing general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as ofDecember 31, 2023 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission"2013 Framework" (COSO). Based on that evaluation, as of December 31, 2023, our management concluded that our internal control over financial reporting was effectiveat a reasonable assurance level based on those criteria. No changes were made to our internal control over financial reporting during the last fiscal quarter that materiallyaffected, or are reasonably likely to materially affect, our internal control over financial reporting. Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s consolidated financial statements included in this AnnualReport on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting, which is included herein. 74Table of Contents Report of Independent Registered Public Accounting Firm The Partners of Natural Resource Partners L.P. Opinion on Internal Control Over Financial Reporting We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, NaturalResource Partners L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on theCOSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheetsof Natural Resource Partners L.P. as of December 31, 2023 and 2022, the related consolidated statements of comprehensive income, partners’ capital and cash flows foreach of the three years in the period ended December 31, 2023, and the related notes and our report dated March 7, 2024 expressed an unqualified opinion thereon. Basis for Opinion The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express anopinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required tobe independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities andExchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assuranceabout whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating thedesign and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactionsand dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectivenessto future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies orprocedures may deteriorate. /s/ Ernst & Young LLP Houston, TexasMarch 7, 2024 75Table of Contents ITEM 9B. OTHER INFORMATION During the fiscal quarter ended December 31, 2023, none of our officers or directors, as defined in Rule 16a-1(f), informed us of the adoption, modification ortermination of any "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as those terms are defined in Item 408 of Regulation S-K. ITEM 9C. DISCLSOURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS Not applicable. 76Table of Contents PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER AND CORPORATE GOVERNANCE As a master limited partnership, we do not employ any of the people responsible for the management of our properties. Instead, we reimburse affiliates of ourmanaging general partner, GP Natural Resource Partners LLC, for their services. The following table sets forth information concerning the directors and officers of GPNatural Resource Partners LLC as of the date of this Annual Report on Form 10-K. Each officer and director is elected for their respective office or directorship on anannual basis. Subject to the Board Representation and Observation Rights Agreement with GoldenTree, RCM is entitled to appoint the members of the Board ofDirectors of GP Natural Resource Partners LLC. Name Age Position with the General PartnerCorbin J. Robertson, Jr. 76 Chairman of the Board and Chief Executive OfficerCraig W. Nunez 62 President and Chief Operating OfficerChristopher J. Zolas 49 Chief Financial OfficerKevin J. Craig 55 Executive Vice PresidentPhilip T. Warman 53 General Counsel and SecretaryGregory F. Wooten 68 Senior Vice President, Chief EngineerGaldino J. Claro 64 DirectorS. Reed Morian 78 DirectorPaul B. Murphy, Jr. 64 DirectorRichard A. Navarre 63 DirectorCorbin J. Robertson, III 53 DirectorStephen P. Smith 63 DirectorLeo A. Vecellio, Jr. 77 Director Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC since 2002. Mr.Robertson, Jr. has vast business experience having founded and served as a director and as an officer of multiple companies, both private and public, and has served onthe boards of numerous non-profit organizations. He has served as the Chief Executive Officer and Chairman of the Board of the general partner of Great NorthernProperties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978, as Chairman of the Board of Directors of New Gauley Coal Corporation since1986, and the general partner of Western Pocahontas Properties Limited Partnership since 1986. Mr. Robertson, Jr. is also Chief Executive Officer and a member of theBoard of Managers of Pocahontas Royalties LLC. He also serves as a Principal with Quintana Capital Group, Chairman of the Board of the Cullen Trust for HigherEducation, Chairman of the Board of KLX Energy Services Holdings, Inc. and is on the boards of the American Petroleum Institute, the National Petroleum Council, theBaylor College of Medicine and the Spirit Golf Association. In 2006, Mr. Robertson, Jr. was inducted into the Texas Business Hall of Fame. Mr. Robertson, Jr. is the fatherof Corbin J. Robertson, III. Craig W. Nunez has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since August 2017 and previously served as ChiefFinancial Officer and Treasurer of GP Natural Resource Partners LLC from January 2015 to August 2017. Prior to joining NRP, Mr. Nunez was an owner and ChiefExecutive Officer of Bocage Group, a private investment company specializing in energy, natural resources and master limited partnerships since March 2012. Inaddition, until joining NRP, he was a FINRA-registered Investment Advisor Representative with Searle & Co since July 2012 and served as an Executive Advisor toCapital One Asset Management since January 2014. From September 2011 through March 2012, Mr. Nunez served as the Executive Vice President and Chief FinancialOfficer of Quicksilver Resources Canada, Inc. Mr. Nunez was Senior Vice President and Treasurer of Halliburton Company from January 2007 until September 2011, andVice President and Treasurer of Halliburton Company from February 2006 to January 2007. Prior to that, he was Treasurer of Colonial Pipeline Company from November1995 to February 2006. Mr. Nunez has been involved in numerous charitable organizations and currently serves on the boards of Goodwill Industries of Houston andMedical Bridges, Inc. Christopher J. Zolas has served as Chief Financial Officer since August 2017 and also served as Treasurer from August 2017 until May 2023. Mr. Zolas served asChief Accounting Officer of GP Natural Resource Partners LLC from March 2015 to August 2017. Prior to joining NRP, Mr. Zolas served as Director of FinancialReporting at Cheniere Energy, Inc., a publicly traded energy company, where he performed financial statement preparation and analysis, technical accounting and SECreporting for five separate SEC registrants, including a master limited partnership. Mr. Zolas joined Cheniere Energy, Inc. in 2007 as Manager of SEC Reporting andTechnical Accounting and was promoted to Director in 2009. Prior to joining Cheniere Energy, Inc., Mr. Zolas worked in public accounting with KPMG LLP from 2002 to2007. Kevin J. Craig was named Executive Vice President of GP Natural Resource Partners LLC in February 2021, after serving as Executive Vice President, Coal of GPNatural Resource Partners LLC since September 2014. Mr. Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr.Craig also represents NRP as one of its appointees to the Board of Managers of Sisecam Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX Transportation. He hasextensive marketing, finance and operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates having beenelected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate Craig served as Chairman of the Committee onEnergy. Mr. Craig did not seek re-election in 2014 and his term ended January 2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig hasserved as the Chairman of the Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber ofCommerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He serves as a member of the Board of Directors of Encova MutualInsurance Company, the West Virginia University Board of Governors and the WVU Medicine Board of Governors. Philip T. Warman has served as General Counsel and Secretary of GP Natural Resource Partners LLC since August 2021. Mr. Warman previously served asExecutive Vice President, General Counsel and Secretary of SandRidge Energy Inc. from August 2010 until June 2019. He was Associate General Counsel for SEC andfinance matters for Spectra Energy Corporation from January 2007 through July 2010. From 1998 through 2006 he practiced law as a corporate finance attorney withVinson & Elkins, LLP in Houston, Texas. Mr. Warman earned a Bachelor of Science in Chemical Engineering from the University of Houston in 1993 and graduated fromthe University of Texas School of Law in 1998. 77Table of Contents Gregory F. Wooten was named Senior Vice President, Chief Engineer of GP Natural Resource Partners LLC in February 2021, after serving as Vice President, ChiefEngineer of GP Natural Resource Partners LLC since December 2013. Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP, Mr. Wootenserved as Vice President, Chief Operating Officer and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties from 1982until 2007. Mr. Wooten has over 35 years of experience in the coal industry, working as a planning and production engineer and is a member of the American Institute ofMining, Metallurgical, and Petroleum Engineers. Mr. Wooten also serves as the President of the National Council of Coal Lessors and is a board member of the WestVirginia, Kentucky, Indiana and Montana Coal Council. He also serves on the board of the Cabell-Huntington Hospital and is a member of the West Virginia SchoolBuilding Authority. Galdino J. Claro joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Claro has 30 years of worldwide executive leadershipexperience in the primary and secondary metals industries and is currently the Chief Executive Officer of the Wilmington Paper Corporation and an Independent Directorof Phoenix Global. From October 2013 to August 2017, Mr. Claro served as the Group Chief Executive Officer and Managing Director of Sims Metal Management wherehe was also a member of the Safety, Health, Environment and Sustainability Committee, the Nomination Governance Committee and the Finance Investment Committee.Before joining Sims Metal Management, Mr. Claro served for four years as the Chief Executive Officer of Harsco Metals and Minerals. He joined Harsco from Aleris,where he served as CEO of Aleris Americas. Before that, he was the CEO of the Metals Processing Group of Heico Companies LLC. During his career with Alcoa Inc.,Mr. Claro served for five years as the President of Alcoa China and for six years in Europe as the Vice President of Soft Alloys Extrusions and the President of AlcoaEurope Extrusions. While in South America, Mr. Claro worked for several different divisions of Alcoa Alumni SA as plant manager, technology manager, new productsdevelopment director and Managing Director of Alcoa Cargo-Van. Before joining Alcoa in 1985, Mr. Claro started his career at Honda-Motogear as a Quality ControlManager where he worked for three years in both Brazil and Japan. S. Reed Morian joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive business experience having served asChairman and Chief Executive Officer of several companies since the early 1980s and serving on the board of other companies. Mr. Morian has served as a member ofthe Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the generalpartner of Great Northern Properties Limited Partnership since 1992. Mr. Morian also serves on the Board of Managers of Pocahontas Royalties, LLC. Mr. Morianworked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief Executive Officer from 1981 to 2006. He has also served as Chairman, ChiefExecutive Officer and President of DX Holding Company from 1989 to 2023. He currently serves as President of Morian Interests LLC. He formerly served on the Boardof Directors for the Federal Reserve Bank of Dallas—Houston Branch from April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March2005 until April 2009. He is currently serving on the Board of Directors of Gulf Capital Bank in Houston. Paul B. Murphy, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Murphy retired from Cadence Bank in April 2023 after a42 year career as a commercial banker serving 21 of those years as a CEO. Mr. Murphy helped raise $1 billion to invest in the distressed banking industry in 2010. Heacquired Cadence Bank and three others and had strong core growth reaching $18 billion in assets. In 2021 Cadence merged with BancorpSouth and today the companyis $48 billion in assets with 400 branches in 9 states and trades on the NYSE (CADE). Previously, Mr. Murphy spent 20 years at Amegy Bank of Texas, helping to steerthat institution from $75 million in assets and a single location to assets of $11 billion and 85 banking centers at the time of his departure as the Chief Executive Officerand a Director in 2009. Mr. Murphy is an advocate of the community and is a board member of Oceaneering International, Inc., Hope and Healing Center and Instituteand the Houston Hispanic Chamber of Commerce. He previously served on the Board of the Houston branch of the Dallas Federal Reserve and the HoustonEndowment. Richard A. Navarre joined the Board of Directors of GP Natural Resource Partners LLC in October 2013. Mr. Navarre brings extensive operating, financial, strategicplanning, public company and coal industry experience to the Board of Directors. Mr. Navarre is former Chairman, President and CEO of Covia Holdings, a leadingprovider of high quality minerals and material solutions for the industrial and energy markets. From 1993 until 2012, Mr. Navarre held senior executive positions withPeabody Energy Corporation, including President-Americas, President and Chief Commercial Officer, Executive Vice President of Corporate Development and ChiefFinancial Officer. Mr. Navarre serves on the Board of Directors of Civeo Corporation, where he serves as Chairman and member of the Environmental, Social, Governanceand Nominating Committee and Arch Resources, where he serves as Chairman of the Personnel and Compensation Committee and member of the Environmental, Social,Governance and Nominating and Governance Committee. He is a member of the Hall of Fame of the College of Business and a member of the Board of Advisors of theCollege of Business and Analytics of Southern Illinois University Carbondale. He is the former Chairman of the Bituminous Coal Operators’ Association. Mr. Navarre isa Certified Public Accountant. Mr. Navarre also has been involved in numerous civic and charitable organizations throughout his career. Corbin J. Robertson, III joined the Board of Directors of GP Natural Resource Partners LLC in May 2013. Mr. Robertson, III has experience with investments in avariety of energy businesses, having served both in management of private equity firms and having served on several boards of directors. He has served as the ChiefExecutive Officer of the general partner of Western Pocahontas Properties Limited Partnership since May 2008, and has served on the Board of Directors of QuintanaMinerals Corporation since 2007 and Western Pocahontas since October 2012. Mr. Robertson, III previously served on the Board of Managers of Premium Resources,LLC. Mr. Robertson, III also co-founded Quintana Energy Partners, an energy-focused private equity firm in 2006 and served as a Managing Director thereof from 2006until December 2010. Mr. Robertson, III previously served as Vice President-Acquisitions for GP Natural Resource Partners LLC from 2003 until 2005. Mr. Robertson, IIIalso serves on the Board of Directors of Quality Magnetite and LL&B Minerals, each of which is in the energy business. Mr. Robertson, III is the son of Corbin J.Robertson, Jr. Mr. Robertson, III previously served as Co-Managing Partner of LKCM Headwater Investments GP, LLC, LKCM Headwater Investments I, L.P., LKCMHeadwater Investments II, LP, LKCM Headwater Investments II Sidecar, LP, LKCM Headwater Investments III, private equity funds that began June 2011. Stephen P. Smith joined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive public company financial experience in thepower and energy industries to the Board of Directors. Mr. Smith formerly served as Chief Financial Officer, Chief Accounting Officer and Director of the general partnerof Columbia Pipeline Partners L.P. from September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and Chief Financial Officer ofColumbia Pipeline Group from July 2015 to June 2016. Mr. Smith served as Executive Vice President and Chief Financial Officer for NiSource, Inc. from August 2008 toJune 2015. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc, including Senior Vice President - Shared Services fromJanuary 2008 to June 2008, Senior Vice President and Treasurer from January 2004 to December 2007, and Senior Vice President - Finance from April 2003 to December2003. Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings extensive experience in the aggregates andcoal mine development industry to the Board of Directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the late1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer, contractor and oilterminal developer/operator in the Mid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with Vecellio &Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996 to November 2002. Mr. Vecellio is the former Chairman of theAmerican Road and Transportation Builders and is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations. 78Table of Contents Corporate Governance Board Meetings and Executive Sessions The Board met seven times in 2023. During 2023, our non-management directors met in executive session several times. The presiding director was Mr. Vecellio, theChairman of our Compensation, Nominating and Governance Committee, or CNG Committee. In addition, our independent directors met several times in executivesession in 2023. Mr. Vecellio was the presiding director at those meetings. Interested parties may communicate with our non-management directors by writing a letter tothe Chairman of the CNG Committee, NRP Board of Directors, 1415 Louisiana Street, Suite 3325, Houston, Texas 77002. Independence of Directors The Board of Directors has affirmatively determined that Messrs. Claro, Navarre, Smith, and Vecellio are independent based on all facts and circumstancesconsidered by the Board, including the standards set forth in Section 303A.02(a) of the NYSE’s listing standards. Because we are a limited partnership as defined inSection 303A of the NYSE’s listing standards, we are not required to have a majority of independent directors on the Board. The Board has an Audit Committee, aCompensation, Nominating and Governance Committee, and a Conflicts Committee, each of which is staffed solely by independent directors. Audit Committee Our Audit Committee is comprised of Mr. Smith, who serves as chairman, Mr. Claro and Mr. Navarre. Mr. Smith and Mr. Navarre are "Audit Committee FinancialExperts" as determined pursuant to Item 407 of Regulation S-K. During 2023, the Audit Committee met six times. Report of the Audit Committee Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements ofthe New York Stock Exchange. The Audit Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all currentregulatory requirements. The Audit Committee Charter is available on our website at www.nrplp.com and is available in print upon request. During 2023, at each of its meetings, the Audit Committee met with the senior members of our financial management team, our general counsel and ourindependent auditors. The Audit Committee had private sessions at certain of its meetings with our independent auditors and the senior members of our financialmanagement team and the general counsel at which candid discussions of financial management, accounting and internal control and legal issues took place. The Audit Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 2023 and reviewed with ourfinancial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors ofour internal controls and the quality of our financial reporting. Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just theacceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financialstatements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewedcertifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairlypresent, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference forconservative policies when a range of accounting options is available. The Audit Committee has discussed with the independent auditors the matters required to be discussed by the applicable requirements of the Public CompanyAccounting Oversight Board (“PCAOB”) and the Commission. The Audit Committee has received the written disclosures and the letter from the independentaccountant required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the Audit Committee concerningindependence, and has discussed with the independent accountant the independent accountant’s independence. In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Audit Committee reviews our Quarterly Reports on Form 10-Qand Annual Reports on Form 10-K prior to filing with the Securities and Exchange Commission. In 2023, the Audit Committee also reviewed quarterly earningsannouncements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Audit Committee relies on thework and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report,express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting principles. In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, andthe Board has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2023, for filing with theSecurities and Exchange Commission. Stephen P. Smith, Chairman Galdino J. Claro Richard A. Navarre 79Table of Contents Compensation, Nominating and Governance Committee Executive officer compensation is administered by the CNG Committee, which is currently comprised of three members: Mr. Vecellio, as Chairman, Mr. Navarre andMr. Smith. During 2023, the CNG Committee met eight times. Our Board of Directors appoints the CNG Committee and delegates to the CNG Committee responsibility for:•reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates to our business;•reviewing and recommending the annual and long-term incentive plans in which our executive officers participate and approving awards thereunder; and•reviewing and approving compensation for the Board of Directors. Our Board of Directors has determined that each CNG Committee member is independent under the listing standards of the NYSE and the rules of the SEC. Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the design and implementation ofcompensation programs for directors and executive officers and other data that the CNG Committee considers as appropriate. In addition, the CNG Committee has thesole authority to retain and terminate any outside counsel or other experts or consultants engaged to assist it in the evaluation of compensation of our directors andexecutive officers. The CNG Committee Charter is available in print upon request. Partnership Agreement Investors may view our partnership agreement and the amendments to the partnership agreement on our website at www.nrplp.com. The partnership agreement isalso filed with the SEC and is available in print to any unitholder that requests them. Corporate Governance Guidelines and Code of Business Conduct and Ethics We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that applies to our management, and complieswith Item 406 of Regulation S-K. Our Corporate Governance Guidelines and our Code of Business Conduct and Ethics are available on our website at www.nrplp.comand are available in print upon request. We intend to disclose future amendments to certain provisions of the Code of Business Conduct and Ethics, and waivers of theCode of Business Conduct and Ethics granted to executive officers and directors, on the website within four business days following the date of the amendment orwaiver. NYSE Certification Pursuant to Section 303A of the NYSE Listed Company Manual, in 2023, Corbin J. Robertson, Jr. certified to the NYSE that he was not aware of any violation bythe Partnership of NYSE corporate governance listing standards. 80Table of Contents ITEM 11. EXECUTIVE COMPENSATION Compensation Discussion and Analysis Overview As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. Ourexecutive officers based in Houston, Texas are employed by Quintana Minerals Corporation (“Quintana”), and our executive officers based in Huntington, West Virginiaare employed by Western Pocahontas Properties Limited Partnership (“Western Pocahontas”). Quintana and Western Pocahontas are controlled by our Chairman andChief Executive Officer and are affiliates of NRP. While our executive officers are employed by affiliates of NRP, each of them has been appointed to serve as an executiveofficer of GP Natural Resource Partners LLC (“GP LLC”), the general partner of NRP (GP) LLC (“NRP GP”), the general partner of NRP. For a more detailed description ofour structure, see "Items 1. and 2. Business and Properties—Partnership Structure and Management" in this Annual Report on Form 10-K. Although our executive officers’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse those companies based on thetime allocated to NRP by each executive officer. Our reimbursement for the compensation of executive officers is governed by our partnership agreement. For purposesof this Compensation Discussion and Analysis, our “named executive officers” are: •Corbin J. Robertson, Jr.—Chairman and Chief Executive Officer•Craig W. Nunez—President and Chief Operating Officer•Christopher J. Zolas—Chief Financial Officer•Philip T. Warman—General Counsel and Secretary•Kevin J. Craig—Executive Vice President In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings thathave the purpose or effect of enabling our general partner to receive distributions. Named Executive Officer Compensation Strategy and Philosophy Under our partnership agreement, each quarter we are required to distribute all of our available cash, as such term is defined in our partnership agreement. TheBoard of Directors considers numerous factors each quarter in determining cash distributions including profitability, cash flow, debt service obligations, marketconditions and outlook, estimated unitholder income tax liability, and the level of cash reserves that the board determines are necessary for future operating and capitalneeds. Our primary objective over the last eight years has been to use all internally generated cash flow to reduce debt while paying distributions to commonunitholders sufficient to cover income tax liability on their share of the partnership’s taxable income. Our compensation philosophy is designed to attract, motivate andretain highly talented executives, while keeping them focused on promoting our strategic objectives to manage the business under current market conditions andposition the partnership as a key beneficiary of the transitional energy economy of the future. Our objective in determining the compensation of our named executiveofficers is to incentivize them to create long-term value for our unitholders and other stakeholders. We believe our compensation programs encourage sustained long-term profitability by making a portion of each named executive officer’s total direct compensation variable and dependent on our achievement of safety, financial andstrategic performance goals as well as the total unitholder return of our common units. Thus, a significant portion of our executives’ total compensation is performance-based and not guaranteed, as further described under “—Components of Compensation.” Although we reimburse Quintana and Western Pocahontas, as applicable, for the applicable portion of our named executive officers’ compensation, the CNGCommittee is responsible for administering our executive officer compensation programs. To help retain and motivate executives, the CNG Committee aims to offercompetitive compensation packages through a mix of cash and long-term, equity-based incentives. The CNG Committee does not have any formal policies for allocatingtotal compensation among the various components. Instead, the CNG Committee uses its judgment, in consultation with the independent compensation consultant, toestablish an appropriate balance of short-term and long-term compensation for such named executive officers for their services to us. The balance may change from yearto year based on the amount of time an executive spends in service to us, our corporate strategy, financial performance and non-financial objectives, among otherconsiderations. 81Table of Contents Summary of Compensation Practices We strive to maintain judicious governance standards and compensation practices by regularly reviewing best practices. The CNG Committee incorporated manybest practices when forming our 2023 compensation program, including the following: What We Do✔Align our executive compensation with long-term performance✔Align executive officers’ interests with those of unitholders✔Engage an independent compensation consultant, NFP Compensation Consultants ("NFP"), to assess our practices✔Maintain trading policies that restrict all employees and directors from pledging or short selling our securities, entering into any derivative transactions with respectto our securities, or otherwise hedging the risk and reward of our securities✔Review the independence of any compensation consultant that is engaged to assist in our compensation analysis✔Provide limited perquisites What We Don’t Do✘Automatically increase salaries each year or make lock-step changes in compensation based on peer group compensation levels or metrics✘Pay guaranteed or multi-year cash bonuses✘Provide significant perquisites✘Provide tax gross-ups The 2023 compensation for executive officers consisted of four primary components:•base salaries;•short-term cash incentive compensation;•long-term equity incentive compensation; and•perquisites and other benefits. Mr. Robertson does not receive a salary in his capacity as Chief Executive Officer. Mr. Robertson is compensated through short-term cash and long-term equityincentive awards, all of which is allocated to NRP. To the extent our named executive officers spend time on non-NRP matters, NRP bears only the proportionate cost oftheir base salaries, short-term cash incentive compensation and perquisites and other benefits. In February of each year, the CNG Committee approves the short-term cash incentive awards for the year just ended and long-term incentive awards for the namedexecutive officers. The CNG Committee considers the performance of the partnership, the performance of the individuals and the outlook for the future in determiningthe amounts of the awards. Each February, the CNG Committee also makes awards of equity-based awards to be settled in common units under the Natural Resource Partners 2017 Long-TermIncentive Plan (the “2017 Plan”) to NRP’s officers in order to incentivize management and align the long-term interests of management and NRP unitholders. 82Table of Contents Role of the CNG Committee The CNG Committee oversees our executive compensation and employee benefit programs, and reviews and approves all compensation decisions relating to ournamed executive officers and directors. The CNG Committee also approves its report for inclusion in this Annual Report and has reviewed and discussed thisCompensation Discussion and Analysis with management. Specifically, the CNG Committee reviews and approves the compensation for our named executive officers. It reviews and approves the annual and long-termincentive plans in which our named executive officers participate, and it also reviews and approves compensation programs for the members of the Board of Directors,as described further below. Role of Independent Compensation Consultant and Market Data The CNG Committee engaged NFP to review our compensation practices for our named executive officers and directors relative to our peers. NFP provides noservices to management or the CNG Committee that are unrelated to the duties and responsibilities of the CNG Committee, and the CNG Committee makes all decisionsregarding the compensation of our named executive officers and directors. NFP reports directly to the CNG Committee, and all work conducted by NFP for us is on behalfof the CNG Committee. The CNG Committee has determined that no conflicts of interest exist as a result of the engagement of NFP. The CNG Committee, with input from NFP, selected our peer group (the “Peer Group”) after reviewing annual revenue, market capitalization, total enterprise valueand total assets of relevant public companies to determine which companies were representative of the marketplace for talent within which we compete. The CNGCommittee reviews the Peer Group annually to ensure continued appropriateness for comparative purposes. The CNG Committee determined that the companies belowreflect an appropriate Peer Group for 2023: Amplify Energy Corp.Enviva Partners, LPRing Energy, Inc.Berry CorporationFalcon Minerals CorporationSilverBow Resources, Inc.Black Stone Minerals, L.P.Kimbell Royalty Partners, LPSisecam Resources LPBrigham Minerals, Inc.NACCO Industries, Inc.Smart Sand, Inc.CatchMark Timber Trust, Inc.PHX Minerals, Inc.SunCoke Energy, Inc.CONSOL Coal Resources LPRamaco Resources, Inc.W&T Offshore Inc.Earthstone Energy Inc.Ranger Oil Corporation NFP provides the CNG Committee with Peer Group data for comparison purposes, such as to compare equity and pay mix practices. Market pay levels are one ofmultiple factors considered by the CNG Committee in setting applicable compensation amounts and determining the appropriate design of incentive compensationprograms. Role of Our Executive Officers in the Compensation Process With respect to 2023 salaries, short-term cash incentive awards and long-term equity incentive awards, Mr. Nunez, our President and Chief Operating Officer,provided Mr. Robertson with recommendations relating to the executive officers other than himself. Mr. Robertson considered those recommendations and provided theCNG Committee with recommendations for all of the executive officers other than himself. Messrs. Robertson and Nunez considered the factors described elsewhere inthis Compensation Discussion and Analysis in recommending, in their discretion, the appropriate amounts of compensation for each named executive officer (other thanfor themselves). Messrs. Robertson and Nunez attended the CNG Committee meetings, other than executive sessions called by the CNG Committee, at which the CNGCommittee deliberated and approved the salaries, short-term cash incentive awards and long-term equity incentive awards for 2023. Messrs. Robertson and Nunez wereexcused from the meetings when the CNG Committee discussed their compensation. 83Table of Contents Components of Compensation Base Salaries With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our named executive officers are paid an annualbase salary by Quintana or Western Pocahontas for services rendered to us by the named executive officers during the fiscal year. We then reimburse Quintana andWestern Pocahontas based on the time allocated to our business by each named executive officer. The base salaries of our named executive officers are reviewed on anannual basis as well as at the time of a promotion or other material change in responsibilities. The CNG Committee reviews and approves the full salaries paid to eachnamed executive officer by Quintana and Western Pocahontas, based on both the actual time allocations to NRP in the prior year and the anticipated time allocations inthe coming year. In determining salaries for our named executive officers for 2023, the CNG Committee considered several factors including the executive’s position and level ofresponsibility within our organization, comparative market data and other external market-based factors. The CNG Committee also considered the individual performance,our partnership’s overall performance during the fiscal year and the individual’s contribution to our overall performance of each named executive officer during 2022.Salaries for 2023 are shown in the Summary Compensation Table below. Short-Term Cash Incentive Compensation Short-term cash incentive awards are determined based on the Partnership meeting and exceeding certain annual financial, strategic objectives and safety goals.Short-term cash incentive awards are used to motivate and reward our named executive officers. Each named executive officer received a short-term cash incentive awardapproved in February 2024 by the CNG Committee. The amounts awarded with respect to 2023 under this program are disclosed in the Summary Compensation Tableunder the Bonus column. The CNG Committee, using recommendations from NFP, determined that cash bonuses would be paid based on a percentage of base salary,with our Chief Executive Officer receiving approximately 2.3 times the amount awarded to the President and Chief Operating Officer for 2023. The CNG Committee usedfree cash flow, strategic objectives and safety as performance measures in determining the amount of bonuses paid under the plan, representing 75%, 20% and 5% of thetotal award, respectively. Based on the level of achievement of the performance measures, the CNG Committee used its discretion to set the level of bonus payments as apercentage of target. The following table shows the performance measures used in the 2023 short-term cash incentive compensation for our named executive officers, together withthe percentage of the total annual cash incentive grant that such component comprises. Each of the components for the named executive officers is described in greaterdetail below: Performance Measure 2023 Portion of Total Target AwardFree Cash Flow 75%Strategic Objectives 20%Safety 5% We believe that these performance measures align our short-term incentive compensation with both unitholder and employee interests by targeting specificperformance goals set forth in the first quarter of each year. By identifying meaningful performance measures, and by assigning greater weight to certain measures, weare able to more closely align compensation to the achievement of those business objectives over which particular employees have the greatest impact. If the target level of performance is achieved with respect to a particular performance measure, the applicable payout percentage for that performance measure willequal 100%. Achievement at the threshold performance level results in a payout percentage for that performance measure that will equal 50%. If the maximum level ofperformance is achieved with respect to a particular performance measure the payout percentage for that measure will equal 200% of target performance, with theexception of safety which is capped at 100%. We interpolate payouts under the annual cash incentive awards for performance levels that fall between the threshold,target and maximum performance levels. There is no payout for performance that does not meet the threshold level criteria and there is no payout in excess of themaximum performance level. 84Table of Contents Free Cash Flow “Free Cash Flow” is calculated as cash flow from operating activities plus return on long-term contract receivable less cash flow used in investing activities,excluding proceeds from asset sales. The CNG Committee utilized the budget approved by the Board of Directors during the annual review process and set the “target”level for this performance measure at 100% of budget. The threshold payout value was set at 80% of the Free Cash Flow budget and the maximum payout value was setat 120% of the budget. We consider this performance measure to be difficult to attain and appropriately reflective of our position in the inherently volatile commoditiesmarket. The following table shows the threshold, target and maximum levels for the 2023 short-term cash incentive compensation plan: Performance Measure Threshold Target MaximumFree Cash Flow $205,120,000 $256,400,000 $307,680,000 Strategic Objectives Strategic Objectives are approved by the Board of Directors each year and reflect the broad strategic objectives of the partnership, which may change year to year.The measure of performance of these strategic objectives is evaluated annually by the CNG Committee and the threshold, target and maximum payouts are at thediscretion of the CNG Committee. Safety Safety is an important emphasis for the Partnership and, the Board of Directors believes, each of the Partnership's stakeholders. Strong safety performance leads toimproved employee performance and lower costs associated with regulatory citations, insurance and litigation matters, which in turn lead to improved operatingperformance. Because of these factors, the CNG Committee uses Reportable Injuries and Lost Time Incidents as a component of the annual incentive compensationplan. Due to the non-operating nature of our business, the “Reportable Injuries and Lost Time Incidents” are set at a target of zero, with threshold or maximum measure.Additionally, the CNG Committee considers the Partnership's completion rate for annual safety trainings with a 100% employee completion rate. 2023 Payout Under the Short-Term Cash Incentive Compensation Plan In early 2024, the CNG Committee evaluated the levels of achievement of the various performance measures for 2023 and made the following determinations: Performance Measure Actual Performance Applicable Payout Percentage Relative Weighting Weighted Payout PercentageFree Cash Flow $313,400,000 200% 75% 150%Strategic Objectives Board Satisfaction 150% 20% 30%Safety 100% 100% 5% 5% 85Table of Contents Based on the actual performance as set forth above, the cumulative amounts listed below were earned under the 2023 short-term cash incentive compensation forthe Partnership's 2023 performance. Name Target as a % of Base Salary Actual payout as a % of Base Salary Dollar Amount of Actual payout ($)Corbin J. Robertson, Jr. (1) 2.3x 2.3x 2,369,918Craig Nunez 100% 185% 1,030,400Christopher J. Zolas 80% 148% 584,226Philip Warman 76% 141% 555,015Kevin Craig (2) 80% 148% 500,034 (1)As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s actual payout.(2)Mr. Craig allocated approximately 88% of his time to NRP during the year ended December 31, 2023, and the amount of short-term cash incentive compensationreflects this allocation. The following table shows the target opportunities available to the named executive officers as a percentage of base salary and the actual payouts as a percentageof their base salaries for each of the last three years: 2021 2022 2023Name Target as % of BaseSalary Actual Payout as %of Target Target as % of BaseSalary Actual Payout as %of Target Target as % of BaseSalary Actual Payout as %of TargetCorbin J. Robertson, Jr. (1) 2.3x 172% 2.3x 195% 2.3x 185%Craig Nunez 100% 172% 100% 195% 100% 185%Christopher J. Zolas 80% 172% 80% 195% 80% 185%Philip Warman 76% 172% 76% 195% 76% 185%Kevin Craig 80% 172% 80% 195% 80% 185% (1)As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s actual payout. 86Table of Contents Long-Term Equity Incentive Compensation We have adopted the 2017 Plan pursuant to which we may grant equity-based compensation to our named executive officers and other officers. Our CNGCommittee believes that awards under the 2017 Plan promote the alignment of the interests of management with those of our unitholders and promote creation of valuefor our unitholders. In 2023, the CNG Committee determined it was appropriate to introduce additional performance measures in connection with long-term compensationto better align executive compensation with the Partnership's performance. We refer to these phantom units issued in 2023 as “2017 Plan Phantom Units.” The 2023awards were made in the form of phantom units that will settle in NRP common units on a one-for-one basis and will accrue tandem distribution equivalent rights(“DERs”) to be paid in cash upon settlement. 2023 Annual Grants The first award of the 2017 Plan Phantom Units granted in February 2023 (“2022 Award”) was to recognize the Partnership's performance in 2022, whereby weachieved 180% of target. In determining the award amounts the CNG Committee used the following key metrics: safety, free cash flow and certain strategic initiatives.These phantom unit awards time-vest ratably over a three-year period following the grant date. The second of the 2017 Plan Phantom Units award granted in February2023 (“2023 Award”) was to provide a revised form of performance-based long-term incentive compensation. This new form included a mix of time-based andperformance-based phantom units awarded at target; 35% are time-based phantom units that will vest ratably over a three-year period and 65% are performance-basedphantom units that will cliff vest at the end of the three-year period with the actual number of units vesting for the performance-based phantom units to be determinedby the performance score. The performance score will be the relative total unit holder return (“TUR”) performance score and the financial performance score, bothweighted at 50%. The 2017 Plan Phantom Units (the 2022 Award and 2023 Award) are subject to forfeiture and will vest on an accelerated basis following death ordisability of the award recipient, following a change in control of NRP, or termination without cause or for good reason. The grant date fair value of the 2017 PlanPhantom Units awarded in 2023 (the 2022 Award and 2023 Award) is disclosed in the Summary Compensation Table under the Stock Awards column. In determining theaward amounts the CNG Committee used a percentage target of base salary. The following table sets forth the long-term equity award targets and number of units granted to each NEO in 2023: 2022 Award 2023 AwardNamed Executive Officer Target as % of BaseSalary Time-Based Target as % of BaseSalary Time-Based Performance-BasedCorbin J. Robertson, Jr. (1) 1.84x 65,791 1.84x 15,866 29,466Craig W. Nunez 224% 35,756 224% 8,623 16,014Christopher J. Zolas 153% 15,071 153% 4,173 7,751Philip T. Warman 85% 10,137 85% 2,311 4,292Kevin J. Craig (2) 90% 10,378 90% 2,380 4,420 (1)As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s actual payout.(2)Although Mr. Craig allocated approximately 88% of his time to NRP during the year ended December 31, 2023, the grants under the 2017 Plan to Mr. Craig do notfactor in such allocation. 87Table of Contents Relative Total Unitholder Return Performance Score For the relative TUR performance score, the performance-based phantom units will be eligible to vest based on the Partnership's TUR relative to the Partnership'sperformance peer group over the three-year performance period. The TUR calculation will be based on a “point-to-point” approach using the 20 calendar-day volume-weighted average of the closing price per share (or unit) of the Partnership or a member of the performance peer group listed below at the beginning and end of theperformance period. In the event that our TUR is negative, the payout will be capped at target, regardless of peer group performance. In the instance of a merger oracquisition of a peer company during the performance period, the company would be removed from the peer group. The performance peer group for the 2023 Awardsconsists of the following companies: Alliance Resource PartnersPeabody Energy CorporationAlpha Metallurgical ResourcesRamaco Resources, Inc.Arch Resources, IncSisecam Resources LPCONSOL Coal Resources LPSunCoke Energy, Inc.Corsa Coal Corp.Warrior Met Coal, IncEnviva Inc. If the target level of performance is achieved, the payout percentage will equal 100%. Achievement at the threshold performance level will result in a payout at 50%of target performance and achievement at the maximum performance level will result in a payout at 200% of target performance. We interpolate payouts for performancelevels that fall between the stated performance levels. There is no payout for performance that does not meet the threshold level and there is no payout in excess of themaximum performance level. The following table shows the performance levels for the 2023 long-term performance-based equity awards: Performance Measure Threshold Target MaximumRelative Total Unitholder Return18th Percentile 45th Percentile91st Percentile Financial Performance Score The financial performance score is calculated based on cumulative three-year free cash flow. “Free Cash Flow” is defined as cash from operating activities plusreturn on long-term contract receivable less cash flow used in investing activities, excluding proceeds from asset sales. Payouts will be determined based on theachievement of cumulative free cash flow relative to targets set by the Committee. We consider this performance measure to be difficult to attain and appropriatelyreflective of our position in the inherently volatile commodities market. 88Table of Contents Perquisites and Other Personal Benefits Both Quintana and Western Pocahontas maintain employee benefit plans that provide our executive officers and other employees with the opportunity to enroll inhealth, dental and life insurance plans. Each of these benefit plans requires the employee to pay a portion of the health and dental premiums, with the applicablecompany paying the remainder. These benefits are offered on the same basis to all employees of Quintana and Western Pocahontas, and the company costs arereimbursed by us to the extent the employee allocates time to our business. In 2023, Quintana and Western Pocahontas maintained tax-qualified 401(k) plans. During 2023, Quintana and Western Pocahontas matched 100% of the first 6.0%of the employee contributions under their respective 401(k) plans. As with the other contributions, any amounts contributed by Quintana and Western Pocahontas arereimbursed by us based on the time allocated by the employee to our business. None of NRP, Quintana or Western Pocahontas maintains a pension plan, a definedbenefit retirement plan or a deferred compensation plan. Other Compensation Policies and Practices Unit Ownership Requirements NRP maintains Unit Ownership and Retention Guidelines (the “ownership guidelines”) that are administered by the CNG Committee and require NRP’s officers whoare required to file ownership reports under Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and certain other officers as designated from time-to-time by the Board or the CNG Committee to retain all common units awarded under any NRP incentive plan (net of any units withheld or sold to cover tax liabilities)until certain ownership guidelines are met. The following table sets for the ownership guidelines. There is no minimum time period required to achieve the unitownership guidelines. Position RequirementChief Executive Officer (1) N/APresident and Chief Operating Officer 3 x SalaryChief Financial Officer 3 x SalaryGeneral Counsel and Secretary 1.5 x SalaryExecutive Vice President 2 x Salary (1)Ownership guidelines due not currently apply to our Chief Executive Officer due to his substantial ownership in NRP. The ownership guidelines also require directors who are not officers to retain common units with a value equal to three times the amount of the annual cashretainer paid to directors. Directors are required to achieve the unit ownership guideline within five years. Until the unit ownership guideline is achieved, each director isencouraged to retain all common units awarded under any NRP incentive plan (net of any units sold to cover tax liabilities). Units that count towards the satisfaction of the officer and director guidelines include common units held directly by the executive officer or director, commonunits owned indirectly by the executive officer or director (e.g., by a spouse or other immediate family member residing in the same household or a trust for the benefit ofthe executive officer or director or his or her family), units granted under NRP’s long-term incentive plans (including phantom units representing the right to receiveunits), and units purchased in the open market (whether purchased before or after the effective date of the ownership guidelines). 89Table of Contents Incentive Compensation Recoupment Policy NRP maintains the Natural Resource Partners L.P. Incentive-Based Compensation Recoupment Policy, which is administered by the CNG Committee and intendedto be compliant with the new clawback rules and regulations that went into effect during 2023. The policy authorizes the Board or committee thereof to recoup incentivecompensation in the event of a restatement of financial statements due to material non-compliance with securities laws, fraud or misconduct. For more information,please see NRP's Incentive-Based Compensation Recoupment Policy attached as Exhibit 97.1 in this Annual Report on form 10-K. Securities Trading Policy Our insider trading policy restricts employees and directors, as well as their designees, from purchasing or selling puts or calls to sell or buy our common units,engaging in short sales with respect to our common units, buying our securities on margin or pledging our securities to secure debt or engaging in any transactions thatwould be deemed to be a hedging transaction involving our securities. Risk Assessment of Compensation Plans We believe that our compensation program does not encourage excessive or unnecessary risk taking. This is primarily due to the fact that our compensationprograms and the compensation arrangements are designed to encourage our employees, including our named executive officers, to focus on both short-term and long-term strategic goals, thereby creating an ownership culture and helping to align the interests of our employees and our unitholders. Accordingly, our compensationprogram is balanced between short-term and long-term incentives, as well as cash and equity-based forms of settlement. Overall, we believe that the balance within our compensation program results in an appropriate compensation structure and that the program does not pose risksthat could have a material adverse effect on our business or financial performance. Report of the Compensation, Nominating and Governance Committee The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management. Basedon the reviews and discussions referred to in the foregoing sentence, the CNG Committee recommended to the Board of Directors that the Compensation Discussionand Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2023. Leo A. Vecellio, Jr., Chairman Richard A. Navarre Stephen P. Smith 90Table of Contents Summary Compensation Table The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation in 2021, 2022 and 2023: Stock All Other Name and Principal Position (1)Year Salary ($) Bonus ($) Awards($) (2) Compensation($) (3) Total ($) Corbin J. Robertson, Jr.—Chief Executive Officer 2023 — 2,369,918 5,638,047 — 8,007,965 2022 — 2,379,068 3,096,757 — 5,475,825 2021 — 2,037,340 946,909 — 2,984,249 Craig W. Nunez—President and Chief Operating Officer 2023 556,973 1,030,400 3,064,159 19,800 4,671,332 2022 530,450 1,034,378 1,683,020 18,300 3,266,148 2021 515,000 885,800 717,032 17,400 2,135,232 Christopher J. Zolas—Chief Financial Officer 2023 394,748 584,226 1,369,645 19,800 2,368,419 2022 375,950 586,482 709,414 18,300 1,690,146 2021 365,000 502,240 412,549 17,400 1,297,189 Philip T. Warman—General Counsel and Secretary (4) 2023 394,748 555,015 849,337 19,800 1,818,900 Kevin J. Craig—Executive Vice President (5) 2023 337,861 500,034 871,561 26,243 1,735,699 (1)In 2023, Messrs. Robertson, Nunez, Zolas, Warman and Craig spent approximately 50%, 100%, 100%, 100% and 88%, respectively, of their time on NRP matters.(2)Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determinedwithout regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see "Item 8. Financial Statements and SupplementaryData—Note 16. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K for more information.(3)Includes portions of 401(k) matching allocated to Natural Resource Partners by Quintana and Western Pocahontas.(4)Mr. Warman was not a named executive officer in 2021 or 2022.(5)Mr. Craig was not a named executive officer in 2021 or 2022. Mr. Craig allocated approximately 88% of his time to NRP during the year ended December 31, 2023 andamounts included under the “Salary,” “Bonus,” and “All Other Compensation” columns reflect this allocation. Amounts included under “Stock Awards” are paid100% by NRP. 91Table of Contents Grants of Plan-Based Awards in 2023 The following table shows the 2017 Plan Phantom Units granted to named executive officers during 2023. Based on the grant, the awards in the table below willeither vest ratably in 2024, 2025 and 2026 or cliff vest in 2026. Upon settlement, an equivalent number of common units will be issued to each named executive officer,subject to withholding. The 2017 Plan Phantom Units also accrue DERs from the grant date, which will be paid out in cash upon settlement following and subject tovesting. 2017 Plan Phantom Units Estimated Future Payouts Under Equity Incentive Plan Awards (1) All other UnitAwards (2) Named Executive Officer Grant Date Threshold (#) Target (#) Maximum (#) Units (#) Grant Date Fair Value($)Corbin J. Robertson, Jr 2/1/2023 14,733 29,466 58,932 1,495,016 2/1/2023 81,657 4,143,031Craig W. Nunez 2/1/2023 8,007 16,014 32,028 812,502 2/1/2023 44,379 2,251,657Christopher J. Zolas 2/1/2023 3,876 7,751 15,502 393,262 2/1/2023 19,244 976,383Philip T. Warman 2/1/2023 2,146 4,292 8,584 217,763 2/1/2023 12,448 631,574Kevin J. Craig 2/1/2023 2,210 4,420 8,840 224,258 2/1/2023 12,758 647,303 (1)The units represent performance-based awards and cliff vest in February 2026. If threshold targets are not met, the award amount will be zero. The number of awardsthat vest will be between zero and the maximum.(2)The units represent time-based awards and vest ratably in February 2024, 2025 and 2026. Employment Agreements None of our named executive officers have an employment agreement. 92Table of Contents Outstanding Equity Awards at December 31, 2023 The table below shows the total number of outstanding 2017 Plan Phantom Units held by each named executive officer at December 31, 2023. Performance-basedunits are valued assuming target is met. Named Executive Officer Unvested 2017 Plan Phantom Units Market Value of Unvested 2017 Plan PhantomUnits ($) (6)Corbin J. Robertson, Jr. (1) 185,510 17,170,806Craig W. Nunez (2) 104,718 9,692,698Christopher J. Zolas (3) 47,804 4,424,738Philip T. Warman (4) 25,337 2,345,193Kevin J. Craig (5) 31,506 2,916,195 (1)156,044 units are time-based and vest ratably in February 2024, 2025 and 2026, and 29,466 units are performance based and cliff vest in February 2026.(2)88,704 units are time-based and vest ratably in February 2024, 2025 and 2026, and 16,014 units are performance based and cliff vest in February 2026.(3)40,053 units are time-based and vest ratably in February 2024, 2025 and 2026, and 7,751 units are performance based and cliff vest in February 2026.(4)21,045 units are time-based and vest ratably in February 2024, 2025 and 2026, and 4,292 units are performance based and cliff vest in February 2026.(5)27,086 units are time-based and vest ratably in February 2024, 2025 and 2026, and 4,420 units are performance based and cliff vest in February 2026.(6)Based on a unit price of $92.56, the closing price for the common units on December 29, 2023, the last trading day in calendar year 2023. Units Vested in 2023 The table below shows the value realized by each named executive officer as a result of the vesting of their phantom unit awards granted under the 2017 Plan: Named Executive Officer 2017 Plan Phantom Units Value Realized on Vesting ($) (1) (2)Corbin J. Robertson, Jr. 69,768 4,089,074Craig W. Nunez 41,816 2,451,874Christopher J. Zolas 19,743 1,158,139Philip T. Warman 1,802 102,858Kevin J. Craig 13,602 797,916 (1)Based on a unit price of $54.08, the closing price for the common units on February 14, 2023.(2)Includes DERs accrued from the issue date to the settlement date. 93Table of Contents Potential Payments upon Termination or Change in Control Upon the occurrence of a change in control or termination without cause of NRP, our general partner, or GP Natural Resource Partners LLC, 2017 Plan PhantomUnits held by each of our named executive officers would immediately vest and become payable and they are entitled to no other benefits because we do not haveemployment contracts. The table below indicates the estimated payments to each named executive officer following a change in control at December 31, 2023. 2017 Plan Equity Awards Named Executive Officer Unvested Phantom Units Market Value ($) (1) Accumulated DERs ($) Total Potential Payments ($)Corbin J. Robertson, Jr. 185,510 17,170,806 1,144,463 18,315,269Craig W. Nunez 104,718 9,692,698 658,938 10,351,636Christopher J. Zolas 47,804 4,424,738 305,789 4,730,527Philip T. Warman 25,337 2,345,193 108,985 2,454,178Kevin J. Craig 31,506 2,916,195 203,322 3,119,517 (1)Calculated based on a unit price of $92.56, the closing price for the common units on December 29, 2023, the last trading day in calendar year 2023. Directors' Compensation for the Year Ended December 31, 2023 For more information regarding the Board and committees thereof, see “Item 10. Directors and Executive Officers of the Managing General Partner and CorporateGovernance” elsewhere in this Annual Report on Form 10-K. Director compensation during 2023 consisted of a $75,000 cash retainer and an award of common unitsunder the 2017 Plan. The units awarded to Board members are fully vested and not subject to forfeiture; however, the Board members had the option in advance ofreceipt of the award to elect to defer settlement of the award until after 90 days following such director’s retirement or earlier departure from the Board. In addition,members of Board committees received $8,000, $7,500 and $5,000 for serving on the audit, compensation, nominating and governance and conflicts committees,respectively, and the chairman of the audit, compensation, nominating and governance and conflicts committees received an additional $20,000, $15,000 and $15,000,respectively, for acting as chairman. The table below shows the directors’ compensation for the year ended December 31, 2023: Name of Director Fees Earned or Paid in Cash ($) 2017 Plan Common Unit Awards ($) (1) Total Compensation ($)S. Reed Morian 75,000 115,021 190,021Richard A. Navarre (2) 110,500 115,021 225,521Corbin J. Robertson, III 75,000 115,021 190,021Stephen P. Smith (3) 110,500 115,021 225,521Leo A. Vecellio, Jr. 102,500 115,021 217,521Paul B. Murphy, Jr. 75,000 115,021 190,021Galdino J. Claro 88,000 115,021 203,021 (1)Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determinedwithout regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see "Item 8. Financial Statements and SupplementaryData—Note 16. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K. All of the phantom units reported in this column were outstanding onDecember 31, 2023 and will vest on February 1, 2024. As of December 31, 2023, each of the current directors hold the following number of outstanding phantom unitawards: Mr. Morian, 2,267; Mr. Navarre, 6,621; Mr. Robertson, 2,267; Mr. Smith, 17,629; Mr. Vecellio, 2,267; Mr. Murphy, 2,267 and Mr. Claro, 2,267.(2)Mr. Navarre elected to defer settlement of his common units awarded under the 2017 Plan in 2018 and 2019 until 90 days following his retirement or earlier departurefrom the Board. As of December 31, 2023, 6,621 phantom units previously awarded to Mr. Navarre were outstanding but only 2,267 were unvested.(3)Mr. Smith elected to defer settlement of his common units awarded under the 2017 Plan in 2018, 2019, 2020, 2021 and 2022 until 90 days following his retirement orearlier departure from the Board. As of December 31, 2023, 17,629 phantom units previously awarded to Mr. Smith were outstanding but only 2,267 were unvested. 94Table of Contents Compensation Committee Interlocks and Insider Participation During the year ended December 31, 2023, Messrs. Vecellio, Navarre, and Smith served on the CNG Committee. None of Messrs. Vecellio, Navarre, and Smith hasever been an officer or employee of NRP or GP LLC. None of our executive officers serve as a member of the board of directors or compensation committee of any entitythat has any executive officer serving as a member of our Board or CNG Committee. Pay Ratio Disclosure The Securities and Exchange Commission has adopted a rule requiring annual disclosure of the ratio of the median employee’s total annual compensation to thetotal annual compensation of the principle executive officer. The personnel providing services to us, including our executive officers, are employed by Quintana or Western Pocahontas. As of December 31, 2023, 55 suchpersons were providing services to us. We identified a new median service provider for 2023 by examining the 2023 total taxable compensation, as reflected in our payrollrecords as reported to the Internal Revenue Service on Form W-2, for all individuals who provided services to us as of December 31, 2023. We did not make anyassumptions, adjustments, or estimates with respect to total cash compensation or equity compensation and we did not annualize the compensation for any serviceproviders that were not employed for all of 2023. After identifying the median service provider based on total compensation, we calculated annual 2023 compensation for the median service provider using thesame methodology used to calculate the Chief Executive Officer’s total compensation as reflected in the Summary Compensation Table above. The median serviceprovider’s annual 2023 compensation was as follows: Name Year Salary ($) Bonus ($) Non-EquityIncentive PlanCompensation ($) Stock Awards ($) All OtherCompensation ($) Total ($)Median Service Provider 2023 101,389 46,893 34,434 — 6,083 188,799 Our 2023 ratio of Chief Executive Officer total compensation of $8,007,965 to our median service provider's total compensation of $188,799 is reasonably estimatedto be 42:1. 95Table of Contents ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following tables set forth, as of February 22, 2024, the amount and percentage of our common units and preferred units beneficially held by (1) each personknown to us to beneficially own 5% or more of any class of our units, (2) by each of our directors and named executive officers and (3) by all directors and executiveofficers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the unitsshown. Percentage of Common Common Name of Beneficial Owner Units Units (1) Corbin J. Robertson, Jr. (2) 2,569,048 19.8%Quintana Management LLC (3) 1,883,986 14.5%The Goldman Sachs Group, Inc. (4) 917,289 7.1%Kevin J. Craig 35,262 * Craig W. Nunez 89,340 * Philip T. Warman 4,557 * Christopher J. Zolas 42,234 * Galdino J. Claro 20,109 * S. Reed Morian (5) 636,508 4.9%Paul B. Murphy, Jr. 22,802 * Richard A. Navarre (6) 16,995 * Corbin J. Robertson III (7) 254,651 2.0%Stephen P. Smith (8) 2,622 * Leo A. Vecellio, Jr. 22,349 * Directors and Officers as a Group (9) 3,748,679 28.9% *Less than one percent.(1)12,960,064 common units issued and outstanding as of February 22, 2024.(2)Mr. Robertson, Jr. may be deemed to beneficially own 668,748 common units owned in his capacity as controlling owner of Quintana Holdings, LP, 1,727,986common units in his capacity as controlling member of Quintana Management LLC, which is the sole member of Western Pocahontas GP LLC, which is the generalpartner of Western Pocahontas Limited Partnership, 156,000 common units in his capacity as the controlling member of Quintana Management LLC, which is thesole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource Partners LLC, which is the general partner of NRP (GP) LP,11,021 common units in his capacity as controlling shareholder of Western Pocahontas Corporation, and 5,293 common units in his capacity as controllingshareholder of GNP Management Corporation. Mr. Robertson, Jr.’s address is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.(3)Quintana Management LLC has voting and dispositive power with respect to 1,727,986 common units in its capacity as sole member of Western Pocahontas GPLLC, which is the general partner of Western Pocahontas Properties Limited Partnership and 156,000 common units in its capacity as the sole member of RobertsonCoal Management LLC, which is the sole member of GP Natural Resource Partners LLC, which is the general partner of NRP (GP) LP. The business address ofQuintana Management LLC is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.(4)According to a Schedule 13G filing with the SEC on February 7, 2024, The Goldman Sachs Group holds shared voting power and shared dispositive power withrespect to 917,289 common units in the Partnership. The business address of The Goldman Sachs Group is 200 West Street, New York, NY 10282.(5)Mr. Morian may be deemed to beneficially own 344,863 common units owned by Shadder Investments and 60,097 common units owned by Mocol Properties, L.P.(6)Does not include 4,354 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Navarre has elected to defer settlement of until 90 daysfollowing the date that he no longer serves on NRP’s board.(7)Mr. Robertson III may be deemed to beneficially own 9,783 common units held by CIII Capital Management, LLC, 10,000 common units held by BHJ Investments LP,19,663 common units held by The Corbin James Robertson III, 2009 Family Trust and 39 common units held by his spouse, Brooke Robertson. The address for CIIICapital Management, LLC, BHJ Investments LP, and The Corbin James Robertson III, 2009 Family Trust is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.The following common units are pledged as collateral for loans: 68,873 common units owned by Mr. Robertson III.(8)Does not include 18,082 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Smith has elected to defer settlement of until 90 days followingthe date that he no longer serves on NRP’s board. Mr. Smith may be deemed to beneficially own 355 common units owned by the SP Smith 2002 Revocable Trust.(9)NRP’s directors and executive officers as a group consists of 13 individuals. 96Table of Contents Percentage of Name of Beneficial Owner Preferred Units Preferred Units GoldenTree Asset Management, LP (1) 71,666 100% (1)The preferred units are owned by funds managed by GoldenTree Asset Management, LP, whose address is 300 Park Ave, New York, NY 10022. Steven A.Tananbaum serves as senior managing member of GoldenTree Asset Management LLC, the general partner of GoldenTree Asset Management, LP. Securities Authorized for Issuance under Equity Compensation Plans The following table shows the securities authorized for issuance under our 2017 Long-Term Incentive Plan as of December 31, 2023. The initial number of commonunits authorized for issuance pursuant to awards under the plan was 800,000 and in March 2022, an additional 800,000 units were authorized for issuance. Number of securities to beissued upon exercise ofoutstanding options, warrantsand rights Weighted-average exerciseprice of outstanding options,warrants and rights Number of securitiesremaining available for futureissuance under equitycompensation plans (excludingsecurities reflected in column(a)) Plan Category (a) (b) (c) Equity compensation plans approved by security holders — — 713,893(1)Equity compensation plans not approved by security holders n/a n/a n/a Total — — 713,893 (1)As of December 31, 2023, 483,483 2017 Plan Phantom Units were outstanding. Each 2017 Plan Phantom Units represents the right to receive one common unit,together with associated distribution equivalent rights. 97Table of Contents ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Relationships with Entities Associated with Corbin J. Robertson, Jr. Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, and Great Northern Properties Limited Partnership are three privately heldcompanies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the "WPP Group". Corbin J. Robertson, Jr.controls the general partner of Western Pocahontas Properties, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman andChief Executive Officer of New Gauley Coal Corporation. Omnibus Agreement As part of the omnibus agreement entered into concurrently with the closing of our initial public offering (the "Omnibus Agreement"), the WPP Group and anyentity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the “GP affiliates,” each agreed that neither they nor their affiliates will, directly orindirectly, engage or invest in entities that engage in the following activities (each, a "restricted business") in the specific circumstances described below:•the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal within the United States; and•the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal within the United States controlled by a paid-up lease ownedby any GP affiliate or its affiliate. "Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the thenoutstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group and its controlled affiliates will not be prohibitedfrom engaging in activities in which they compete directly with us. A GP affiliate may, directly or indirectly, engage in a restricted business if:•the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets ofthe restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.•the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of therestricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.•the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of theconflicts committee) has elected not to cause us to purchase these assets under the procedures described below.•its ownership in the restricted business consists solely of a non-controlling equity interest. For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate. The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in bythe WPP Group at closing of our initial public offering (and except as described below under "—Pocahontas Royalties LLC"), may not exceed $75 million. For purposesof this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value ofthe entity as a whole, without regard for any lesser ownership interest to be acquired. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and therestricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase therestricted business. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million andthe restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offerus the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph, "restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restrictionsummarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate. If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair marketvalue and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon ascommercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market valueand other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within twoyears for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate mayoperate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group. 98Table of Contents If, at the end of the two-year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinionof the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the generalpartner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives thesecond offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with theconcurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will beunder no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned. In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects thefair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevantGP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offerprocedures described above will recommence. If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly heldlimited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to beacquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPPGroup may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures describedabove. The Omnibus Agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of theWPP Group under the Omnibus Agreement terminate when the WPP Group and its affiliates cease to participate in the control of the general partner. For moreinformation, see the Omnibus Agreement attached as Exhibit 10.3 to this Annual Report on Form 10-K. Pocahontas Royalties LLC On February 28, 2020, Pocahontas Royalties LLC (“Pocahontas Royalties”) completed the acquisition of a private company that owns approximately one millionacres of mineral rights and leases coal to coal mine operators in Central Appalachia. Pocahontas Royalties is controlled by Corbin J. Robertson, Jr. and members of hisfamily. Reed Morian, one of the directors of GP Natural Resource Partners LLC, also serves on the Board of Managers of Pocahontas Royalties. In connection with the closing of the acquisition, we and Pocahontas Royalties entered into a limited waiver of the Omnibus Agreement pursuant to which wewaived the provision of the Omnibus Agreement that restricts Mr. Robertson, Jr. and his affiliates (other than NRP) from owning, operating or investing in fee coal in theUnited States with an aggregate fair market value in excess of $75 million. Mr. Robertson had previously offered NRP the opportunity to participate in the acquisition andwe determined, after due consideration, not to participate. In addition, on February 28, 2020, we and Pocahontas Royalties entered into a right of first offer agreement pursuant to which Pocahontas Royalties granted usthe exclusive right of first offer to purchase any assets (or entities holding such assets) proposed to be sold at any time by Pocahontas Royalties or any of itssubsidiaries with a fair market value exceeding $2 million (individually or in the aggregate), excluding surface acreage, assets or rights (other than surface rights that areappurtenant to or necessary for the development of mineral rights). Provided that Pocahontas Royalties has provided us the opportunity to make a first offer within thetime periods specified in the agreement, Pocahontas Royalties will be under no obligation to accept any offer timely made by us and may determine, in its sole discretion,to consummate a transaction with a third party free and clear of any obligations to us. Preferred Unitholder Board Representation and Observation Rights Agreement Effective on March 2, 2017, in connection with the closing of the issuance of the Preferred Units, we entered into the Board Representation and ObservationRights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant to the Board Rights Agreement, Blackstone appointed one member toserve on the Board of Directors and one observer to attend meetings of the Board of Directors. Pursuant to the Board Rights Agreement, Blackstone's rights to appointa member of the Board and an observer terminate at such time as Blackstone, together with their affiliates, no longer own at least 20% of the total number of preferredunits issued on the closing date, together with all PIK units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). Following the time thatBlackstone (and their affiliates) no longer own the Minimum Preferred Unit Threshold and until such time as GoldenTree (together with their affiliates) no longer own theMinimum Preferred Unit Threshold, GoldenTree shall have the one-time option to appoint either one person to serve as a member of the Board of Directors or oneperson to serve as a Board of Directors observer. To the extent GoldenTree elects to appoint a Board of Directors member and later remove such board designee,GoldenTree may then elect to appoint a Board of Directors observer. In 2023, we repurchased all of Blackstone's preferred units, which were subsequently retired and nolonger remain outstanding, and all rights of Blackstone related thereto ceased as a result. In connection with these repurchases, Blackstone's board designee resignedfrom the Board of Directors. GoldenTree did not exercise its one-time option pursuant to the Board Rights Agreement to appoint either a director or an observer to theBoard of Directors within 30 days of receipt of notice that Blackstone (and its affiliates) no longer own the Minimum Preferred Unit Threshold and GoldenTree no longerhas the right to appoint either a director or an observer to the Board of Directors. For more information on the Preferred Units, including the rights of the holders thereof,see "Item 8. Financial Statements and Supplementary Data—Note 4. Class A Convertible Preferred Units and Warrants" elsewhere in this Annual Report on Form 10-K. Office Building in Huntington, West Virginia We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The initial 10-year term of the lease expired atthe end of 2018. On January 1, 2019, we entered into a new lease on the building for a five-year base term, with five additional five-year renewal options. We paidapproximately $0.8 million to Western Pocahontas under the lease during the year ended December 31, 2023. Relationship with Cadence Bank, N.A. Paul B. Murphy, Jr. one of the members of the Board of Directors, is the Chairman of Cadence Bank, N.A., which is a lender under Opco's revolving credit facilityand has received customary fees and interest payments in connection therewith. We paid approximately $2.1 million in interest and fees under the credit facility toCadence Bank, N.A during the year ended December 31, 2023. 99Table of Contents Conflicts of Interest Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group andPocahontas Royalties) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLChave duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a dutyto manage our Partnership in a manner beneficial to us and our unitholders. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the "DelawareAct", provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a generalpartner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions modifying the fiduciary duties thatwould otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts ofinterest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards,might constitute breaches of fiduciary duty under applicable Delaware law. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partnerwill resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the Board of Directors of such resolution. Thepartnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolvingconflicts of interest. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict isconsidered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:•approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or courseof action that has not received approval;•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or•fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable oradvantageous to us. In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement,consider:•the relative interests of any party to such conflict and the benefits and burdens relating to such interest;•any customary or accepted industry practices or historical dealings with a particular person or entity;•generally accepted accounting practices or principles; and•such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. In addition, GoldenTree has certain consent rights. In the exercise of these consent rights, conflicts of interest could arise between us and GoldenTree. Conflicts of interest could arise in the situations described below, among others. Actions taken by our general partner may affect the amount of cash available for distribution to unitholders. The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:•amount and timing of asset purchases and sales;•cash expenditures;•borrowings;•the issuance of additional common units; and•the creation, reduction or increase of mineral rights in any quarter. In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings thathave the purpose or effect of enabling our general partner to receive distributions. For example, in the event we have not generated sufficient cash from our operations to pay the quarterly distribution on our common units, our partnershipagreement permits us to borrow funds which may enable us to make this distribution on all outstanding common units. The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliatesmay not borrow funds from us or our subsidiaries. 100Table of Contents We do not have any officers or employees. We rely on officers and employees of GP Natural Resource Partners LLC and its affiliates. We do not have any officers or employees and rely on officers and employees of GP Natural Resource Partners LLC and its affiliates. Affiliates of GP NaturalResource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater thanour activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GPNatural Resource Partners LLC are not required to work full time on our affairs. Certain of these officers devote significant time to the affairs of the WPP Group or itsaffiliates and are compensated by these affiliates for the services rendered to them. We reimburse our general partner and its affiliates for expenses. We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff andsupport services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable mannerdetermined by our general partner in its sole discretion. Our general partner intends to limit its liability regarding our obligations. Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our generalpartner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our generalpartner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us. Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us,the right to enforce the obligations of our general partner and its affiliates in our favor. Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-length negotiations. The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on termsthat are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnershipagreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are theresult of arm’s-length negotiations. All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us. Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may beprovided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind. We may not choose to retain separate counsel for ourselves or for the holders of common units. The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and havecontinued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our generalpartner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders ofcommon units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on theother, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of apartnership agreement to restrict such fiduciary duties. Our general partner’s affiliates may compete with us. The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership ofinterests in us. Except as provided in our partnership agreement and the Omnibus Agreement, affiliates of our general partner will not be prohibited from engaging inactivities in which they compete directly with us. The Conflicts Committee Charter is available upon request. Director Independence For a discussion of the independence of the members of the Board of Directors of our managing general partner under applicable standards, see "Item 10.Directors and Executive Officers of the Managing General Partner and Corporate Governance—Corporate Governance—Independence of Directors," which isincorporated by reference into this Item 13. Review, Approval or Ratification of Transactions with Related Persons If a conflict or potential conflict of interest arises between our general partner and its affiliates (including the WPP Group and Pocahontas Royalties) on the onehand, and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under "—Conflicts of Interest." Pursuant to our Code of Business Conduct and Ethics, conflicts of interest are prohibited as a matter of policy, except under guidelines approved by the Board ofDirectors and as provided in the Omnibus Agreement and our partnership agreement. For the year ended December 31, 2023 there were no transactions where suchguidelines were not followed. 101Table of Contents ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended, and we engaged Ernst & Young LLP to audit our accounts andassist with tax compliance for fiscal 2023 and 2022. All of our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board ofDirectors. The following table presents fees for professional services rendered by Ernst & Young LLP: 2023 2022 Audit Fees (1) $972,500 $904,137 Tax Fees (2) 442,270 437,400 (1)Audit fees include fees associated with the annual integrated audit of our consolidated financial statements and internal controls over financial reporting, separateaudits of subsidiaries and reviews of our quarterly financial statement for inclusion in our Form 10-Q and comfort letters; consents; work related to acquisitions;assistance with and review of documents filed with the SEC.(2)Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1. Audit and Non-Audit Services Pre-Approval Policy I. Statement of Principles Under the Sarbanes-Oxley Act of 2002 (the "Act"), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversightof the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by theindependent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the SEC hasissued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of theengagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the "Policy"), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditormay be pre-approved. The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee ("general pre-approval") or require the specific pre-approval of the AuditCommittee ("specific pre-approval"). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficientprocedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it willrequire specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels orbudgeted amounts will also require specific pre-approval by the Audit Committee. For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The AuditCommittee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiaritywith our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage orcontrol risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative. The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services andmay determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services. The appendices to the Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any generalpre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. For the audit, pre-approval is forthe fiscal year as the time between approval and the actual issuance of the audit may be more than 12 months. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will addor subtract to the list of general pre-approved services from time to time, based on subsequent determinations. The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the AuditCommittee’s responsibilities to pre-approve services performed by the independent auditor to management. Ernst & Young LLP, our independent auditor reviews this Policy annually and it does not adversely affect its independence. 102Table of Contents II. Delegation As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Stephen P. Smith, the Chairman of theAudit Committee. Mr. Smith must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting. III. Audit Services The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annualfinancial statement audit (including required quarterly reviews), subsidiary audits and other procedures required to be performed by the independent auditor to be ableto form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testingperformed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services alsoinclude the attestation engagement for the independent auditor’s report on internal controls for financial reporting. The Audit Committee monitors the audit servicesengagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in auditscope, partnership structure or other items. In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other auditservices, which are those services that only the independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits forour subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documentsissued in connection with securities offerings. IV. Audit-related Services Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financialstatements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does notimpair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accountingconsultations related to accounting, financial reporting or disclosure matters not classified as "Audit Services"; assistance with understanding and implementing newaccounting and financial reporting guidance from rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures relatedto accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal controlreporting requirements. V. Tax Services The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advicewithout impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes itmay grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would notimpair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of theindependent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance andthe tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officeror outside counsel to determine that the tax planning and reporting positions are consistent with this Policy. VI. Pre-Approval Fee Levels or Budgeted Amounts Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Anyproposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overallrelationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determinethe appropriate ratio between the total amount of fees for audit, audit-related and tax services. VII. Procedures All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submittedto the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services areincluded within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of anysuch services rendered by the independent auditor. Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the Audit Committee by both theindependent auditor and the Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with theSEC’s rules on auditor independence. 103Table of Contents PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a)(1) and (2) Financial Statements and Schedules (1) See "Item 8. Financial Statements and Supplementary Data."(2) All schedules are omitted because they are not required or because the information is immaterial or provided elsewhere in the Consolidated FinancialStatements and Notes thereto. (a)(3) Sisecam Wyoming LLC Financial Statements The financial statements of Sisecam Wyoming LLC required pursuant to Rule 3-09 of Regulation S-X are included in this filing as Exhibit 99.1. (a)(4) Exhibits ExhibitNumberDescription3.1Fifth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of March 2, 2017 (incorporated by referenceto Exhibit 3.1 to Current Report on Form 8-K filed on March 6, 2017).3.2Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011 (incorporated by reference to Exhibit 3.1to Current Report on Form 8-K filed on December 16, 2011).3.3Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of October 31, 2013 (incorporated byreference to Exhibit 3.1 to Current Report on Form 8-K filed on October 31, 2013).3.4Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference toExhibit 3.4 of Annual Report on Form 10-K for the year ended December 31, 2002).3.5Certificate of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1filed April 19, 2002, File No. 333-86582).4.1Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference toExhibit 4.1 to Current Report on Form 8-K filed June 23, 2003).4.2First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers4.2First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchaserssignatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on July 20, 2005).4.3Second Amendment, dated as of March 28, 2007, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and thepurchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 29, 2007).4.4First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on July 20, 2005).4.5Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 29, 2007).4.6Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 26, 2009).4.7Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the purchasers signatory thereto(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April 21, 2011).4.8Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to Current Report on Form8-K filed June 23, 2003).4.9Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed June 23, 2003).4.10Form of Series D Note (incorporated by reference to Exhibit 4.12 to Annual Report on Form 10-K filed February 28, 2007). 104Table of Contents ExhibitNumberDescription4.11Form of Series E Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed March 29, 2007).4.12Form of Series F Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 7, 2009).4.13Form of Series G Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 7, 2009).4.14Form of Series H Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 5, 2011).4.15Form of Series I Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 5, 2011).4.16Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 15, 2011).4.17Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on October 3, 2011).4.18Registration Rights Agreement, dated as of January 23, 2013, by and among Natural Resource Partners L.P. and the Investors named therein(incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on January 25, 2013).4.19Third Amendment, dated as of June 16, 2015, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holdersnamed therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 18, 2015).4.20Fourth Amendment, dated as of September 9, 2016, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and theholders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 12, 2016).4.21Indenture, dated April 29, 2019, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as issuers, and Wilmington Trust, NationalAssociation, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 2, 2019).4.22Form of 9.125% Senior Notes due 2025 (contained in Exhibit 1 to Exhibit 4.21).4.23Registration Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P. and the Purchasers named therein(incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 6, 2017).4.24Form of Warrant to Purchase Common Units (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 6, 2017).4.25Description of Equity Securities of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.25 to Annual Report on Form 10-K filed onFebruary 27, 2020).10.1Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank,N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and JointBookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 18, 2015).10.2First Amendment, dated as of June 3, 2016, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP(Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells FargoSecurities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 toCurrent Report on Form 8-K filed on June 7, 2016).10.3First Amended and Restated Omnibus Agreement, dated as of April 22, 2009, by and among Western Pocahontas Properties Limited Partnership, GreatNorthern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP)LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed May 7,2009).10.4Limited Liability Company Agreement of Sisecam Wyoming LLC, dated June 30, 2014 (incorporated by reference to Exhibit 10.1 to Current Report onForm 8-K filed by Sisecam Resources LP on July 2, 2014).10.5Amendment No. 1 to the Limited Liability Company Agreement of Sisecam Wyoming LLC dated November 5, 2015 (incorporated by reference to Exhibit10.22 to Annual Report on Form 10-K filed by Sisecam Resources LP on March 11, 2016). 105Table of Contents ExhibitNumberDescription10.6Second Amendment, dated as of March 2, 2017, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP(Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells FargoSecurities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.3 toCurrent Report on Form 8-K filed on March 6, 2017).10.7Fourth Amendment, dated as of April 3, 2019, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP(Operating) LLC and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on April 9, 2019).10.8Master Assignment Agreement and Fifth Amendment to Third Amended Credit Agreement, dated as of August 9, 2022 by and among NRP (Operating)LLC, the Lenders party thereto, the Exiting Lenders, and Zions Bancorporation, N.A. dba Amegy Bank, as administrative agent for the Lenders, asSwingline Lender, and as an Issuing Bank (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 11, 2022). 10.9Sixth Amendment to the Third Amended and Restated Credit Agreement, dated as of May 11, 2023, by and among NRP (Operating) LLC, the lendersparty thereto and Zions Bancorporation, N.A. dba Amegy Bank, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1to Current Report on Form 8-K filed on May 15, 2023).10.10New Lender Agreement, dated as of May 11, 2023, by and among NRP (Operating) LLC, Zions Bancorporation, N.A. dba Amegy Bank, and Gulf CapitalBank (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on May 15, 2023). 10.11New Lender Agreement, dated as of February 1, 2024, by and among NRP (Operating) LLC, Zions Bancorporation, N.A. dba Amegy Bank, and SummitCommunity Bank (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on February 6, 2024).10.12Commitment Increase Agreement dated as of February 14, 2024, by and among NRP (Operating) LLC, Zions Bancorporation, N.A. dba Amegy Bank,and Frost Bank (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on February 20, 2024).10.13New Lender Agreement, dated as of September 1, 2022 by and among NRP (Operating) LLC, the Borrower, Zions Bancorporation, N.A. dba AmegyBank, in its capacity as administrative agent under the Fifth Amendment to Third Amended Credit Agreement and Prosperity Bank, the New Lender(incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 8, 2022). 10.14New Lender Agreement, dated as of April 8, 2019, by and among NRP (Operating) LLC and the lenders party thereto (incorporated by reference toExhibit 10.2 to Current Report on Form 8-K filed on April 9, 2019).10.15Board Representation and Observation Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P., Robertson CoalManagement LLC, GP Natural Resource Partners LLC, NRP (GP) LP, BTO Carbon Holdings L.P. and the GoldenTree Purchasers named therein(incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March 6, 2017)10.16Master Amendment and Supplement to Coal Mining and Transportation Lease Agreements and Parent Guaranty dated June 30, 2020 by and amongNRP (Operating) LLC, WPP LLC, Hod LLC, Independence Land Company, LLC, Williamson Transport LLC, Foresight Energy LP, Foresight Energy GPLLC, Foresight Energy LLC, Macoupin Energy, LLC, Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC, Foresight EnergyResources LLC, and Foresight Energy Operating LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on July 1, 2020).10.17Limited Waiver dated February 28, 2020 by Natural Resource Partners L.P., GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC(incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 3, 2020).10.18Right of First Offer Agreement dated as of February 28, 2020 by and among Pocahontas Royalties LLC, Natural Resource Partners L.P., GP NaturalResource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC. (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March3, 2020).10.19+Natural Resource Partners L.P. 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January17, 2018).10.20+Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit 4.5 to Registration Statement on FormS-8 filed on February 9, 2018).10.21+Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 filed on February 9,2018).10.22+Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-Kfiled on February 27, 2020).10.23+Form of Phantom Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 10.14 to Annual Report on Form 10-K filedon February 27, 2020).10.24+Form of Phantom Unit Award Agreement (Directors with Deferral Election) (incorporated by reference to Exhibit 10.15 to Annual Report on Form 10-Kfiled on February 27, 2020).21.1*List of Subsidiaries of Natural Resource Partners L.P.23.1*Consent of Ernst & Young LLP.23.2*Consent of BDO USA, P.C.23.3*Consent of Deloitte & Touche LLP.31.1*Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.31.2*Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.32.1**Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.32.2**Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.97.1*Natural Resource Partners L.P. Incentive-Based Compensation Recoupment Policy, dated August 2, 2023.99.1*Financial Statements of Sisecam Wyoming LLC as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021. 106Table of Contents ExhibitNumberDescription101.INS*Inline XBRL Instance Document101.SCH*Inline XBRL Taxonomy Extension Schema Document101.CAL*Inline XBRL Taxonomy Extension Calculation Linkbase Document101.DEF*Inline XBRL Taxonomy Extension Definition Linkbase Document101.LAB*Inline XBRL Taxonomy Extension Labels Linkbase Document101.PRE*Inline XBRL Taxonomy Extension Presentation Linkbase Document104*Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101) *Filed herewith**Furnished herewith+Management compensatory plan or arrangement 107Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized. NATURAL RESOURCE PARTNERS L.P. By:NRP (GP) LP, its general partner By:GP NATURAL RESOURCE PARTNERS LLC, its general partner Date: March 7, 2024 By:/s/ CORBIN J. ROBERTSON, JR. Corbin J. Robertson, Jr. Chairman of the Board, Director and Chief Executive Officer (Principal Executive Officer) Date: March 7, 2024 By:/s/ CHRISTOPHER J. ZOLAS Christopher J. Zolas Chief Financial Officer (Principal Financial and Accounting Officer) 108Table of Contents Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and inthe capacities and on the dates indicated. Date: March 7, 2024 /s/ GALDINO J. CLARO Galdino J. Claro Director Date: March 7, 2024 /s/ S. REED MORIAN S. Reed Morian Director Date: March 7, 2024 /s/ PAUL B. MURPHY, JR. Paul B. Murphy, Jr. Director Date: March 7, 2024 /s/ RICHARD A. NAVARRE Richard A. Navarre Director Date: March 7, 2024 /s/ CORBIN J. ROBERTSON III Corbin J. Robertson III Director Date: March 7, 2024 /s/ STEPHEN P. SMITH Stephen P. Smith Director Date: March 7, 2024 /s/ LEO A. VECELLIO, JR. Leo A. Vecellio, Jr. Director 109Exhibit 21.1 List of Subsidiaries of Natural Resource Partners L.P. NRP (Operating) LLCNRP Finance CorporationWPP LLCACIN LLCWBRD LLCHod LLCShepard Boone Coal Company LLCGatling Mineral, LLCIndependence Land Company, LLCWilliamson Transport, LLCRivervista Mining, LLCNRP Trona LLCBRP LLCBRP Minerals LLCCoVal Leasing Company, LLC Exhibit 23.1 Consent of Independent Registered Public Accounting Firm We consent to the incorporation by reference in the following Registration Statements: 1) Registration Statement (Form S-3 No. 333-217205) of Natural Resource Partners L.P., 2) Registration Statement (Form S-3 No. 333-187883) of Natural Resource Partners L.P., 3) Registration Statement (Form S-3 No. 333-262435) of Natural Resource Partners L.P., and 4) Registration Statement (Form S-8 No. 333-222970) pertaining to the Natural Resource Partners L.P. 2017 Long-Term Incentive Plan; of our reports dated March 7, 2024, with respect to the consolidated financial statements of Natural Resource Partners L.P., and the effectiveness of internal control overfinancial reporting of Natural Resource Partners L.P., included in this Annual Report (Form 10-K) of Natural Resource Partners L.P. for the year ended December 31, 2023. /s/ Ernst & Young LLP Houston, TexasMarch 7, 2024 Exhibit 23.2 Consent of Independent Registered Public Accounting Firm We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-217205, 333-187883, 333-262435) and Form S-8 (No. 333-222970)of Natural Resource Partners LP of our report dated March 7, 2024, relating to the financial statements of Sisecam Wyoming LLC, which appears in this Annual Reporton Form 10-K of Natural Resource Partners LP. /s/ BDO USA, P.C. Charlotte, North CarolinaMarch 7, 2024 Exhibit 23.3 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement Nos. 333-217205, 333-187883, and 333-262435 on Form S-3 and Registration No. 333-222970 onForm S-8 of Natural Resource Partners L.P., of our report dated March 15, 2022, relating to the financial statements of Sisecam Wyoming LLC for the year endedDecember 31, 2021, appearing in this Annual Report on Form 10-K of Natural Resource Partners L.P. for the year ended December 31, 2023. /s/ Deloitte & Touche LLP Atlanta, GeorgiaMarch 7, 2024 Exhibit 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER I, Corbin J. Robertson, Jr., certify that: 1I have reviewed this report on Form 10-K of Natural Resource Partners L.P. 2Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statementsmade, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financialcondition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange ActRules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant andhave: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and 5The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’sauditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions); a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. By:/s/ Corbin J. Robertson, Jr. Corbin J. Robertson, Jr. Chief Executive Officer Date:March 7, 2024 Exhibit 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER I, Christopher J. Zolas, certify that: 1.I have reviewed this report on Form 10-K of Natural Resource Partners L.P. 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statementsmade, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financialcondition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange ActRules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant andhave: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’sauditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions); a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. By:/s/ Christopher J. Zolas Christopher J. Zolas Chief Financial Officer Date:March 7, 2024 Exhibit 32.1 CERTIFICATION OFCHIEF EXECUTIVE OFFICEROF GP NATURAL RESOURCE PARTNERS LLCPURSUANT TO 18 U.S.C. § 1350 In connection with the accompanying report on Form 10-K for the year ended December 31, 2023 filed with the Securities and Exchange Commission on the datehereof (the “Report”), I, Corbin J. Robertson, Jr., Chief Executive Officer of GP Natural Resource Partners LLC, the general partner of the general partner of NaturalResource Partners L.P. (the “Company”), hereby certify, to my knowledge, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. By:/s/ Corbin J. Robertson, Jr. Corbin J. Robertson, Jr. Chief Executive Officer Date:March 7, 2024 Exhibit 32.2 CERTIFICATION OFCHIEF FINANCIAL OFFICEROF GP NATURAL RESOURCE PARTNERS LLCPURSUANT TO 18 U.S.C. § 1350 In connection with the accompanying report on Form 10-K for the year ended December 31, 2023 filed with the Securities and Exchange Commission on the datehereof (the “Report”), I, Christopher J. Zolas, Chief Financial Officer of GP Natural Resource Partners LLC, the general partner of the general partner of Natural ResourcePartners L.P. (the “Company”), hereby certify, to my knowledge, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. By:/s/ Christopher J. Zolas Christopher J. Zolas Chief Financial Officer Date:March 7, 2024 Exhibit 97.1Natural Resources Partners L.P.Incentive-Based Compensation Recoupment Policy(this “Policy”) Adopted by the Compensation, Nominating and Governance Committee of the Board of Directors (the “Committee”) of GP Natural Resource Partners LLC (“GPLLC”), the general partner of NRP (GP) LP (the “General Partner”), the general partner of Natural Resource Partners L.P. (the “Partnership”) on August 2, 2023. 1. Recoupment. If the Partnership is required to prepare a Restatement, the Administrator (defined below) shall, unless determined to be Impracticable, takereasonably prompt action to recoup all Recoverable Compensation from any Covered Person. This Policy is in addition to (and not in lieu of) any right of repayment,forfeiture or off-set against any Covered Person that may be available under applicable law or otherwise (whether implemented prior to or after adoption of thisPolicy). The Administrator may, in its sole discretion and in the exercise of its business judgment, determine whether and to what extent additional action isappropriate to address the circumstances surrounding any recovery of Recoverable Compensation tied to a Restatement and to impose such other discipline as itdeems appropriate. 2. Method of Recoupment. Subject to applicable law, the Administrator may seek to recoup Recoverable Compensation by (i) requiring a Covered Person torepay such amount to the Partnership; (ii) offsetting a Covered Person’s other compensation; or (iii) such other means or combination of means as the Administrator,in its sole discretion, determines to be appropriate. To the extent that a Covered Person fails to repay all Recoverable Compensation to the Partnership as determinedpursuant to this Policy, the Partnership shall take all actions reasonable and appropriate to recover such amount, subject to applicable law. The applicable CoveredPerson shall be required to reimburse the Partnership for any and all expenses reasonably incurred (including legal fees) by the Partnership in recovering such amount. 3. Administration of Policy. The Committee shall have full authority to administer, amend or terminate this Policy unless the Board elects to administer thethis Policy (such administrator the “Administrator”). The Administrator shall, subject to the provisions of this Policy, make such determinations and interpretationsand take such actions in connection with this Policy as it deems necessary, appropriate or advisable. All determinations and interpretations made by the Administratorshall be final, binding and conclusive. Notwithstanding anything in this Section 3 to the contrary, no amendment or termination of this Policy shall be effective if suchamendment or termination would (after taking into account any actions taken by the Partnership contemporaneously with such amendment or termination) cause thePartnership to violate any federal securities laws, rules of the U.S. Securities and Exchange Commission (the “SEC”) or the rules of any national securities exchange ornational securities association on which the Partnership’s securities are then listed. The Administrator shall consult with the Partnership’s audit committee, chieffinancial officer and chief accounting officer, as applicable, as needed in order to properly administer and interpret any provision of this Policy. 4. Acknowledgement by Executive Officers. The Administrator may provide notice to and seek written acknowledgement of this Policy from each ExecutiveOfficer; provided that the failure to provide such notice or obtain such acknowledgement shall not affect the applicability or enforceability of this Policy. 5. No Indemnification. Notwithstanding the terms of any of the Partnership’s organizational documents, any corporate policy or any contract, thePartnership shall not indemnify any Covered Person against the loss of any Recoverable Compensation. 6. Disclosures and Record Keeping. The Partnership shall make all disclosures and filings with respect to this Policy and maintain all documents and recordsthat are required by the applicable rules and forms of the SEC (including, without limitation, Rule 10D-1 under the Securities Exchange Act of 1934 (the “ExchangeAct”)) and any applicable exchange listing standard. 7. Governing Law. The validity, construction, and effect of this Policy and any determinations relating to this Policy shall be construed in accordance withthe laws of the State of Delaware without regard to its conflicts of laws principles. 8. Successors. This Policy shall be binding and enforceable against all Covered Persons and their beneficiaries, heirs, executors, administrators or other legalrepresentatives. 9. Fraud and Misconduct. In addition, in the event of a determination by the Administrator that a Covered Executive has engaged in fraud (“Fraud”) ormisconduct (including, but not limited to the violation of an applicable code of conduct or a criminal conviction) (“Misconduct”), the Administrator shall, to the extentpermitted by applicable law, have the right (but not the obligation) as to such Covered Person, to cause GP LLC to require the reimbursement or forfeiture by suchCovered Executive of a portion of such Covered Person’s Incentive-Based Compensation, as determined in the Administrator’s sole discretion. In determining whetheror not to cause GP LLC to pursue reimbursement or forfeiture under Section 9 or this Policy, the Administrator shall not be required to cause GP LLC to seekreimbursement or forfeiture if the Administrator determines that it would not be in the best interests of GP LLC, the General Partner or the Partnership, or theAdministrator determines that such reimbursement or forfeiture cannot be accomplished with reasonable efforts. In making such determinations, the Administratormay take into account all facts and circumstances that it determines to be relevant. 1 10. Definitions. In addition to terms otherwise defined in this Policy, the following terms, when used in this Policy, shall have the following meanings: “Applicable Period” means the three completed fiscal years preceding the earlier of: (i) the date that the Administrator, or the officer or officers of thePartnership authorized to take such action if Administrator action is not required, concludes, or reasonably should have concluded, that the Partnership is required toprepare a Restatement; or (ii) the date a court, regulator, or other legally authorized body directs the Partnership to prepare a Restatement. The Applicable Period shallalso include any transition period (that results from a change in the Partnership’s fiscal year) of less than nine months within or immediately following the threecompleted fiscal years. For purposes of this Policy, the Administrator shall be deemed to have reasonably concluded that a Restatement is required on the date thatthe Partnership’s Audit Committee or the Partnership’s chief accounting officer, as applicable, informs the Administrator in writing that such a Restatement will berequired, unless the Audit Committee informs the Administrator that an alternative date is more accurate for purposes of determining the Applicable Period. “Covered Person” means any person who receives Recoverable Compensation. “Executive Officer” includes the Partnership’s president, principal financial officer, principal accounting officer (or if there is no such accounting officer, thecontroller), any vice-president of the Partnership in charge of a principal business unit, division, or function (such as sales, administration, or finance), any otherofficer who performs a policy-making function, or any other person (including any executive officer of the Partnership’s controlled affiliates) who performs similarpolicy-making functions for the Partnership. “Financial Reporting Measure” means a measure that is determined and presented in accordance with the accounting principles used in preparing thePartnership’s financial statements (including “non-GAAP” financial measures, such as those appearing in earnings releases), and any measure that is derived whollyor in part from such measure. Stock price and total shareholder return (“TSR”) are Financial Reporting Measures. Examples of additional Financial Reporting Measuresinclude measures based on: revenues, net income, free cash flow, operating income, financial ratios, EBITDA, liquidity measures, return measures (such as return onassets), profitability of one or more segments, sales per square foot, same store sales, revenue per user or cost per employee. “Impracticable” means, after exercising a normal due process review of all the relevant facts and circumstances and taking all steps required by Exchange ActRule 10D-1 and any applicable exchange listing standard, the Administrator determines that recovery of the Incentive-Based Compensation is impracticable because:(i) it has determined that the direct expense that the Partnership would pay to a third party to assist in recovering the Incentive-Based Compensation would exceed theamount to be recovered; (ii) it has concluded that the recovery of the Incentive-Based Compensation would violate home country law adopted prior to November 28,2022; or (iii) it has determined that the recovery of Incentive-Based Compensation would cause a tax-qualified retirement plan, under which benefits are broadlyavailable to the Partnership’s employees, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder. “Incentive-Based Compensation” includes any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a FinancialReporting Measure; however it does not include: (i) base salaries; (ii) discretionary cash bonuses; (iii) awards (either cash or equity) that are based upon subjective,strategic or operational standards; and (iv) equity awards that vest solely on the passage of time. “Received” – Incentive-Based Compensation is deemed “Received” in any Partnership fiscal period during which the Financial Reporting Measure specifiedin the Incentive-Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period. “Recoverable Compensation” means all Incentive-Based Compensation (calculated on a pre-tax basis) Received after October 2, 2023 by a person: (i) afterbeginning service as an Executive Officer; (ii) who served as an Executive Officer at any time during the performance period for that Incentive-Based Compensation;(iii) while the Partnership had a class of securities listed on a national securities exchange or national securities association; and (iv) during the Applicable Period, thatexceeded the amount of Incentive-Based Compensation that otherwise would have been Received had the amount been determined based on the Financial ReportingMeasures, as reflected in the Restatement. With respect to Incentive-Based Compensation based on stock price or TSR, when the amount of erroneously awardedcompensation is not subject to mathematical recalculation directly from the information in a Restatement, the amount must be based on a reasonable estimate of theeffect of the Restatement on the stock price or TSR upon which the Incentive-Based Compensation was received. “Restatement” means an accounting restatement of any of the Partnership’s financial statements due to the Partnership’s material noncompliance with anyfinancial reporting requirement under U.S. securities laws, including any required accounting restatement to correct an error in previously issued financial statementsthat is material to the previously issued financial statements (often referred to as a “Big R” restatement), or that would result in a material misstatement if the error werecorrected in the current period or left uncorrected in the current period (often referred to as a “little r” restatement). As of the effective date of this Policy (but subjectto changes that may occur in accounting principles and rules following the effective date), a Restatement does not include situations in which financial statementchanges did not result from material non-compliance with financial reporting requirements, such as, but not limited to retrospective: (i) application of a change inaccounting principles; (ii) revision to reportable segment information due to a change in the structure of the Partnership’s internal organization; (iii) reclassificationdue to a discontinued operation; (iv) application of a change in reporting entity, such as from a reorganization of entities under common control; (v) adjustment toprovision amounts in connection with a prior business combination; and (vi) revision for stock splits, stock dividends, reverse stock splits or other changes in capitalstructure. 2 Exhibit 99.1 Sisecam Wyoming LLC(A Majority-Owned Subsidiary of Sisecam Chemicals Wyoming LLC) Financial Statements as of December 31, 2023 and 2022 and for the Years Ended December 31, 2023, 2022, and 2021, and Reports ofIndependent Registered Public Accounting Firms 1 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Chemicals Wyoming LLC) TABLE OF CONTENTS Page Number REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No. 243)3 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No. 34)5 BALANCE SHEETS AS OF DECEMBER 31, 2023 AND 20226 STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 20217 STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 2023, 2022 AND 20218 STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 20219 NOTES TO THE FINANCIAL STATEMENTS10 2 Report of Independent Registered Public Accounting Firm Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying balance sheets of Sisecam Wyoming LLC (the “Company”) as of December 31, 2023 and 2022, the related statements of operationsand comprehensive income, members’ equity, and cash flows for each of the years then ended, and the related notes (collectively referred to as the “financialstatements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and theresults of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States ofAmerica.Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statementsbased on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required tobe independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States ofAmerica. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of materialmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financialreporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinionon the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to becommunicated to the Board of Managers and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especiallychallenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as awhole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures towhich it relates.Agreements and Transactions with Affiliates As presented in the financial statements and further described in Note 13 to the financial statements, the Company’s accounts receivable – affiliates, due to affiliates,cost of products sold – affiliates, selling, general and administrative expenses – affiliates account balances were $55,171 thousand, $4,882 thousand, $5,343 thousand,and $20,753 thousand as of and for the year ended December 31, 2023, respectively. As the Company is a subsidiary and investee within two different global groupstructures, agreements directly between the Company and other affiliates, or indirectly between affiliates the Company does not control, can have a significant impacton recorded amounts or disclosures in the Company's financial statements, including any commitments and contingencies between the Company and affiliates or,potentially, third parties.We identified the agreements and transactions with affiliates as a critical audit matter. Management’s judgment was required in performing cost allocations and auditingthese elements involved especially challenging auditor judgement due to the nature and extent of audit effort and knowledge required on the relationships and potentialrelated costs allocations to address these matters. 3 The primary procedures we performed to address this critical audit matter included: •Testing the Company’s affiliate listing for the year ended December 31, 2023, including testing the completeness and accuracy of the identification of theCompany’s affiliate relationships, transactions, and commitments and contingencies originating outside of the Company by: (i) reading internal minutes, publicly available financial filings and news sources related to the Company and its affiliates outside of the Company, (ii) confirming with the Company's ultimate parent companies the affiliate relationships, transactions, and commitments and contingencies are identified anddisclosed by the Company, (iii) testing the accuracy of the cost allocations to ensure they are being recorded in the appropriate financial statement accounts. /s/ BDO USA, P.C. We have served as the Company’s auditor since 2022. Charlotte, North Carolina March 7, 2024 4 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Managers and Members ofSisecam Wyoming LLCAtlanta, Georgia Opinion on the Financial Statements We have audited the accompanying statements of operations and comprehensive income, members' equity, and cash flows of Sisecam Wyoming LLC (the “Company”)for the year ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly,in all material respects, the results of the Company’s operations and cash flows for the year ended December 31, 2021, in conformity with accounting principles generallyaccepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statementsbased on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to beindependent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement,whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part ofour audit, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness ofthe Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. /s/ Deloitte & Touche LLP Atlanta, GeorgiaMarch 15, 2022 We began serving as the Company's auditor in 2008. In 2022 we became the predecessor auditor. 5 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Chemicals Wyoming LLC) BALANCE SHEETSAS OF DECEMBER 31, 2023 AND 2022(In thousands of dollars) 2023 2022 ASSETS CURRENT ASSETS: Cash and cash equivalents $6,476 $21,165 Accounts receivable, net 150,526 170,843 Accounts receivable-affiliates 55,171 53,924 Inventory 37,538 47,747 Other current assets 4,043 46,758 Total current assets 253,754 340,437 PROPERTY, PLANT, AND EQUIPMENT, NET 255,796 261,428 OTHER NON-CURRENT ASSETS 28,335 31,487 TOTAL ASSETS $537,885 $633,352 LIABILITIES AND MEMBERS' EQUITY CURRENT LIABILITIES: Current portion of long-term debt $9,030 $8,805 Accounts payable 27,531 37,066 Due to affiliates 4,882 6,061 Accrued expenses 50,410 59,326 Total current liabilities 91,853 111,258 LONG-TERM DEBT 104,147 128,177 OTHER NON-CURRENT LIABILITIES 15,386 16,113 Total liabilities 211,386 255,548 COMMITMENTS AND CONTINGENCIES (See Note 12) MEMBERS' EQUITY: Members’ equity — Sisecam Resources LP 170,062 173,497 Members’ equity — NRP Trona LLC 163,394 166,694 Accumulated other comprehensive income (6.957) 37,613 Total members' equity 326,499 377,804 TOTAL LIABILITIES AND MEMBERS' EQUITY $537,885 $633,352 See notes to financial statements. 6 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Chemicals Wyoming LLC) STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOMEFOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021(In thousands of dollars) 2023 2022 2021 SALES - OTHERS $ 771,340 $ 720,120 $540,139 SALES - AFFILIATES 2,250 — — Total net sales 773,590 720,120 540,139 COST OF PRODUCTS SOLD 530,318 542,409 456,121 COST OF PRODUCTS SOLD - AFFILIATES 5,343 15,136 3,468 Total cost of products sold 585,661 557,545 459,589 GROSS PROFIT 187,929 162,575 80,550 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - AFFILIATES 20,753 19,261 16,635 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES - OTHERS 2,600 5,377 3,731 OPERATING INCOME 164,576 137,937 60,184 OTHER INCOME (EXPENSE): Interest income 1,382 — — Interest expense (6,335) (5,752) (5,042)Other expense, net (74) (120) (83) Total other expense, net (5,027) (5,872) (5,125) NET INCOME 159,549 132,065 55,059 Other comprehensive (loss) income on derivative financial instruments (44,570) 31,644 5,897 COMPREHENSIVE INCOME $114,979 $163,709 $60,956 See notes to financial statements. 7 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Chemicals Wyoming LLC) STATEMENTS OF MEMBERS' EQUITYFOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021(In thousands of dollars) Accumulated Sisecam NRP Trona OtherComprehensive Total Members' Resources LP LLC Income (Loss) Equity Balance at January 1, 2021 $136,459 $131,108 $72 $267,639 Allocation of net income 28,080 26,979 — 55,059 Capital distribution to members (11,730) (11,270) — (23,000)Other comprehensive income — — 5,897 5,897 Balance at December 31, 2021 $152,809 $146,817 $5,969 $305,595 Allocation of net income 67,353 64,712 — 132,065 Capital distribution to members (46,665) (44,835) — (91,500)Other comprehensive income — — 31,644 31,644 Balance at December 31, 2022 $173,497 $166,694 $37,613 $377,804 Allocation of net income 81,370 78,179 — 159,549 Capital distribution to members (84,805) (81,479) — (166,284)Other comprehensive loss — — (44,570) (44,570) Balance at December 31, 2023 $170,062 $163,394 $(6,957) $326,499 See notes to financial statements. 8 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Chemicals Wyoming LLC) STATEMENTS OF CASH FLOWSFOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021(In thousands of dollars) 2023 2022 2021 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $159,549 $132,065 $55,059 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 31,038 27,598 31,468 Loss on disposal of assets, net 885 4,085 965 Other non-cash items 316 690 (487)(Increase) decrease in: Accounts receivable - affiliates (1,247) (4,407) (4,768)Accounts receivable, net 20,318 (53,958) (34,325)Inventory 9,048 (18,428) 303 Other current and non-current assets (94) (43) (2,069)Increase (decrease) in: Accounts payable (9,006) 15,203 5,000 Accrued expenses and other liabilities (9,135) 19,920 5,715 Due to affiliates (1,179) 3,933 (554) Net cash provided by operating activities 200,493 126,658 56,307 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (25,055) (28,264) (25,654)Insurance proceeds — — 809 Net cash used in investing activities (25,055) (28,264) (24,845) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings on revolving credit facility 197,000 158,000 83,500 Borrowings on other long-term debt — — 29,000 Repayments on revolving credit facility (212,000) (136,000) (116,000)Repayments on other long-term debt (8,843) (8,630) (3,031)Debt issuance costs — — (1,394)Cash distribution to members (166,284) (91,500) (23,000) Net cash used in financing activities (190,127) (78,130) (30,925) NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS (14,689) 20,264 537 CASH AND CASH EQUIVALENTS: Beginning of year 21,165 901 364 End of year $6,476 $21,165 $901 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Interest paid during the year $6,115 $5,113 $4,541 SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING ACTIVITIES: Capital expenditures on account $2,240 $2,772 $4,105 See notes to financial statements. 9 SISECAM WYOMING LLC(A Majority Owned Subsidiary of Sisecam Chemicals Wyoming LLC) NOTES TO FINANCIAL STATEMENTSAS OF DECEMBER 31, 2023 AND 2022 AND FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021(Dollars in thousands) 1. Organizational Structure A 51% membership interest in Sisecam Wyoming LLC (the "Company," "we," "us," or "our,") is owned by Sisecam Chemicals Wyoming LLC (“SCW LLC"). NRPTrona LLC, a wholly owned subsidiary of Natural Resource Partners L.P. ("NRP") owns a 49% membership interest in the Company. SCW LLC is 100% owned bySisecam Chemicals Resources LLC ("Sisecam Chemicals,") which is 60% owned by Sisecam USA Inc. ("Sisecam USA") and 40% owned by Ciner Enterprises Inc.("Ciner Enterprises"). Sisecam USA is a direct wholly-owned subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş, a Turkish Corporation ("Şişecam Parent"), which isan approximately 51%-owned subsidiary of Turkiye Is Bankasi Turkiye Is Bankasi ("Isbank"). Şişecam Parent is a global company operating in soda ash, chromiumchemicals, flat glass, auto glass, glassware glass packaging and glass fiber sectors. Şişecam Parent was founded over 88 years ago, is based in Turkey and is one ofthe largest industrial publicly-listed companies on the Istanbul exchange. With production facilities in several continents and in several countries, Sisecam is one ofthe largest glass and chemicals producers in the world. Ciner Enterprises is a direct wholly-owned subsidiary of WE Soda Ltd., a U.K. Corporation (“WE Soda”). WE Soda is a direct wholly-owned subsidiary of KEW Soda Ltd., a U.K. corporation (“KEW Soda”), which is a direct wholly owned subsidiary of Akkan Enerji veMadencilik Anonim Şirketi (“Akkan”). Akkan is directly and wholly owned by Turgay Ciner, the Chairman of the Ciner Group (“Ciner Group”), a Turkishconglomerate of companies engaged in energy and mining (including soda ash mining), media and shipping markets. Prior to 2023, Sisecam Resources LP (“SisecamLP”) owned 51% interest in the Company. Sisecam LP was a master limited partnership traded on the New York Stock Exchange that was owned approximately 72%by SCW LLC, approximately 2% by Sisecam Resource Partners LLC (the “general partner” or “Sisecam GP,” and approximately 26% by the general public. In 2023,SWC LLC dissolved Sisecam LP and Sisecam GP and became the direct owner of 51% of the Company. 2. Nature of Operations and Summary of Significant Accounting Policies Nature of Operations The Company is in the business of mining trona ore to produce soda ash. All of our soda ash processed is currently sold to various domestic and internationalcustomers. Sisecam Chemicals is the exclusive sales agent for the Company. Sisecam Chemicals has leveraged the distributor network established by Sisecam Parentwhile independently reviewing current and potential distribution partners to optimize the Company’s reach into each market. A summary of the significant accounting policies is as follows: Basis of Presentation - The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the UnitedStates of America. Use of Estimates - The preparation of financial statements, in accordance with accounting principles generally accepted in the United States of America, requiresmanagement to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at thedates of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from thoseestimates. Revenue Recognition - The Company’s revenues are recognized upon satisfaction of our performance obligations, that is, delivery and transfer of title to theproduct to our customers as discussed below. Additionally, the Company has made an accounting policy election to account for shipping and handling activitiesas fulfillment costs. We have one reportable segment, and our revenue is derived from the sale of soda ash which is our sole and primary good and service. Performance Obligations. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer. A contract’s transactionprice is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. At contract inception,we assess the goods and services promised in contracts with customers and identify performance obligations for each promise to transfer to the customer, agood or service that is distinct. To identify the performance obligations, the Company considers all goods and services promised in the contract regardless ofwhether they are explicitly stated or are implied by customary business practices. From its analysis, the Company determined that the sale of soda ash iscurrently its only performance obligation. Many of our customer volume commitments are short-term and our performance obligations for the sale of soda ashare generally limited to single purchase orders. •When performance obligations are satisfied. Substantially all of our revenue is recognized at a point-in-time when control of goods transfers to thecustomer. •Transfer of Goods. The Company uses standard shipping terms across each customer agreement with very few exceptions. Control transfer occurs atthe point at which the customer has the ability to direct the use of and obtain substantially all remaining benefits from the asset. The time at whichdelivery and transfer of title, and therefore control, occurs ranges from the point when the product leaves the Company’s facilities (including leasedterminals) to agreed upon delivery points. Agreed upon delivery points at which control of the product transfers includes points where productreaches the port of loading, a vessel, or other agreed location, thereby rendering our performance obligation fulfilled. •Payment Terms. Our payment terms vary by the type and location of our customers. The term between invoicing and when payment is due is notsignificant and consistent with typical terms in the industry. •Variable Consideration. We recognize revenue as the amount of consideration that we expect to receive in exchange for transferring promised goodsor services to customers. We do not adjust the transaction price for the effects of a significant financing component, as the time period betweencontrol transfer of goods and services and expected payment is one year or less. At the time of sale, we estimate provisions for different forms ofvariable consideration (discounts, rebates, and pricing adjustments) based on historical experience, current conditions and contractual obligations, asapplicable. The estimated transaction price is typically not subject to significant reversals. We adjust these estimates when the most likely amount ofconsideration we expect to receive changes, although these changes are typically immaterial. 10 •Returns, Refunds and Warranties. In the normal course of business, the Company does not accept returns, nor does it typically provide customerswith the right to a refund. •Freight. In accordance with FASB Accounting Standard Codification, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), the Companymade a policy election to treat freight and related costs that occur after control of the related good transfers to the customer as fulfillment activitiesinstead of separate performance obligations. Therefore, freight is recognized as part of the cost of products sold at the point in which control of sodaash has transferred to the customer. Revenue Disaggregation. In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with customers into geographical regions.The Company determined that disaggregating revenue into these categories achieved the disclosure objectives to depict how the nature, timing, amount anduncertainty of revenue and cash flows are affected by economic factors. Refer to Note 14, “Segment Reporting,” for revenue disaggregated into geographicalregions. Revenue Contract Balances. The timing of revenue recognition, billings and cash collections results in billed receivables, unbilled receivables (contractassets), and customer advances and deposits (contract liabilities). •Contract Assets. At the point of transfer of control of product, the Company has an unconditional right to payment generally that is only dependenton the passage of time. In general, customers are billed and a receivable is recorded at the point in which transfer of control has taken place. Thesebilled receivables are reported as “Accounts Receivable, net” on the Balance Sheets as of December 31, 2023 and December 31, 2022. There were nocontract assets as of December 31, 2023 and December 31, 2022. •Contract Liabilities. There may be situations where customers are required to prepay a portion of the transaction price. In such instances, a contractliability will be recorded. There were no contract liabilities as of December 31, 2023 and December 31, 2022. Freight Costs - The Company includes freight costs billed to customers for shipments administered by the Company in gross sales. The related freight costsincurred by the Company along with cost of products sold are deducted from gross sales to determine gross profit. Cash and Cash Equivalents - The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cashequivalents. Cash equivalents consist primarily of money market deposit accounts. Accounts Receivable - We determine expected credit losses for recorded receivables based on information about past events, including historical experience,current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. Inventory - Inventory is carried at the lower of cost or net realizable value. Cost is determined using the first-in, first-out method for raw material and finished goodsinventory and the weighted average cost method for stores inventory. Costs include raw materials, direct labor and manufacturing overhead. Net realizable value isdefined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. •Raw material inventory includes material, chemicals and natural resources being used in the mining and refining process. •Finished goods inventory is the finished product soda ash. •Stores inventory includes parts, materials and operating supplies which are typically consumed in the production of soda ash and currently available for futureuse. If the inventory has been used within the preceding twelve months, it is classified as current assets and remainder is classified as non-current assets. Property, Plant, and Equipment - Property, plant, and equipment are stated at cost less accumulated depreciation. Depreciation is computed over the estimateduseful lives of depreciable assets, using the straight-line method. The estimated useful lives applied to depreciable assets are as follows: Useful LivesLand improvements10 yearsDepletable land15 - 60 yearsBuildings and building improvements10-30 yearsComputer hardware3-5 yearsMachinery and equipment5-20 years The Company's policy is to evaluate property, plant, and equipment for impairment whenever events or changes in circumstances indicate that its carrying amountmay not be recoverable. An indicator of potential impairment would include situations when the estimated future undiscounted cash flows are less than the carryingvalue. The amount of any impairment then recognized would be calculated as the difference between estimated fair value and the carrying value of the asset. 11 Derivative Instruments and Hedging Activities - The Company may enter into derivative contracts from time to time to manage exposure to the risk of exchange ratechanges on its foreign currency transactions, the risk of changes in natural gas prices, and the risk of the variability in interest rates on borrowings. Gains andlosses on derivative contracts qualifying for hedge accounting are reported as a component of the underlying transactions. The Company follows hedgeaccounting for its hedging activities. All derivative instruments are recorded on the balance sheet at their fair values. The accounting for changes in the fair valueof a derivative depends on the intended use of the derivative and the resulting designation. The Company designates its derivatives based upon criteriaestablished for hedge accounting under generally accepted accounting principles. For a derivative designated as a fair value hedge, the gain or loss is recognizedin earnings in the period of change together with the offsetting gain or loss on the hedged item attributed to the risk being hedged. For a derivative designated as acash flow hedge, the effective portion of the derivative’s gain or loss is initially reported as a component of accumulated other comprehensive income (loss) andsubsequently reclassified into earnings when the hedged exposure affects earnings. Upon reclassification into earnings, the cash flow hedge is also reflected in thestatement of cash flows as a part of the changes in accrued derivatives fair value. For derivatives not designated as hedges, the gain or loss is reported in earningsin the period of change. When the Company has natural gas physical forward contracts, they are accounted for under the normal purchases and normal salesscope exception. The Company has interest rate swap contracts, designated as cash flow hedges, to mitigate our exposure to possible increases in interest rates. The swap contractsconsist of one individual $12,500 swap with an aggregate notional value of $12,500 at December 31, 2023 and two individual $12,500 swaps with an aggregatenotional value of $25,000 at December 31, 2022. The swap outstanding at December 31, 2023 matures in 2024. We enter into financial gas swap contracts, designated as cash flow hedges, to mitigate volatility in the price of natural gas related to a portion of the natural gas weconsume. These contracts generally have various maturities through 2024. These contracts had an aggregate notional value of $22,778 and $39,679 at December31, 2023 and December 31, 2022, respectively. The following table presents the fair value of derivative assets and liabilities and the respective balance sheet locations as of: Assets Liabilities December 31, 2023 December 31, 2022 December 31, 2023 December 31, 2022 (in thousands)Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedges: Interest rate swap contracts - currentOther current assets $315 Other current assets $ 204 Accrued Expenses $ — Accrued Expenses $— Financial gas swap contracts - currentOther current assets 269 Other current assets 43,399 Accrued Expenses 7,541 Accrued Expenses 7,921 Interest rate swap contracts - non-currentOther non-current assets — Other non-current assets 782 Other non-currentliabilities — Other non-currentliabilities — Financial gas swap contracts - non-currentOther non-current assets — Other Non-current assets 1,498 Other non-currentliabilities — Other non-currentliabilities 507 Total derivatives designated as hedging instruments $584 $45,883 $7,541 $8,428 12 Income Tax - The Company is organized as a pass-through entity for federal income tax purposes and therefore is not subject to federal or certain state incometaxes. As a result, our members are responsible for income taxes based on their respective share of taxable income. Net income for financial statement purposes maydiffer significantly from taxable income reportable to members as a result of differences between the tax basis and financial reporting basis of assets and liabilitiesand the taxable income allocation requirements under the membership agreement. Reclamation Costs - The Company is obligated to return the land beneath its refinery and tailings ponds to its natural condition upon completion of operations andis required to return the land beneath its rail yard to its natural condition upon termination of the various lease agreements. The Company accounts for its land reclamation liability as an asset retirement obligation, which requires that obligations associated with the retirement of a tangiblelong-lived asset be recorded as a liability when those obligations are incurred, with the amount of the liability initially measured at fair value. Upon initiallyrecognizing a liability for an asset retirement obligation, an entity must capitalize the cost by recognizing an increase in the carrying amount of the related long-livedasset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset.Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The estimated original liability calculated in 1996 for the refinery and tailing ponds was calculated based on the estimated useful life of the mine, which was 80 years,and on external and internal estimates as to the cost to restore the land in the future and state regulatory requirements. The liability was discounted using aweighted average credit-adjusted risk-free rate of approximately 6% and is being accreted throughout the estimated life of the related assets to equal the totalestimated costs with a corresponding charge being recorded to cost of products sold. The Company has constructed a rail yard to facilitate loading and switching of rail cars. The Company is required to restore the land on which the rail yard isconstructed to its natural conditions. The original estimated liability for restoring the rail yard to its natural condition was calculated based on the land lease life of30 years and on external and internal estimates as to the cost to restore the land in the future. The liability is discounted using a credit-adjusted risk-free rate of 4%and is being accreted throughout the estimated life of the related assets to equal the total estimated costs with a corresponding charge being recorded to cost ofproducts sold. Fair Value of Financial Instruments - The following methods and assumptions were used to estimate the fair values of each class of financial instruments: The Company measures certain financial and non-financial assets and liabilities at fair value on a recurring basis. Fair value is defined as the price that would bereceived to sell an asset or paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on themeasurement date. Fair value disclosures are reflected in a three-level hierarchy, maximizing the use of observable inputs and minimizing the use of unobservableinputs. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Fair valueaccounting requires that these financial assets and liabilities be classified into one of the following three categories: •Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for an identical asset or liability in an active market. •Level 2-inputs to the valuation methodology include quoted prices for a similar asset or liability in an active market or model-derived valuations in which allsignificant inputs are observable for substantially the full term of the asset or liability. •Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement of the asset or liability. Financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, derivative financial instruments andlong-term debt. The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses approximate their fair valuebecause of the nature of such instruments. Our long-term debt and derivative financial instruments are measured at their fair values with Level 2 inputs based onquoted market values for similar but not identical financial instruments. The carrying value of the Sisecam Wyoming Credit Facility (as defined below) materially reflects the fair value as the rate is variable and its key terms are similar toindebtedness with similar amounts, durations and credit risks. The fair value of the Sisecam Wyoming Equipment Financing Arrangement was $34,662 versus acarrying value of $36,177 at December 31, 2023. See Note 8, “Debt,” for additional information on our debt arrangements. Subsequent Events - The Company has evaluated all subsequent events through March 7, 2024, the date the financial statements were available to be issued. SeeNote 15, "Subsequent Events," for additional information. Recently Issued and Adopted Accounting Standards - In November 2023, the FASB issued ASU 2023-07, Segment Reporting (topic 280): Improvements toReportable Segment Disclosures (“ASU 2023-07”) requiring entities to disclose its significant segment expense categories and amount for each reportable segment. The Company is currently evaluating ASU 2023-07 and the impact to the Company’s financial statements. 3. ACCOUNTS RECEIVABLE, NET Trade receivables, net and other receivables balances at January 1, 2022 were $109,677 and $7,208, respectively. Accounts receivable, net consisted of the followingat December 31: 2023 2022 Trade receivables, net $141,898 $162,957 Other receivables 8,628 7,886 Total $150,526 $170,843 13 4. INVENTORY Inventory consisted of the following at December 31: 2023 2022 Raw materials $13,262 $14,776 Finished goods 12,651 23,670 Stores inventory, current 11,625 9,301 Total $37,538 $47,747 5. PROPERTY, PLANT, AND EQUIPMENT, NET Property, plant, and equipment, net consisted of the following at December 31: 2023 2022 Land and land improvements $192 $192 Depletable land 4,031 4,031 Buildings and building improvements 169,036 168,209 Computer hardware 2,737 6,592 Machinery and equipment 748,702 732,262 Total 924,698 911,286 Less accumulated depreciation, depletion and amortization (703,479) (679,966)Total net book value 221,219 231,320 Construction in progress 34,577 30,108 Property, plant, and equipment, net $255,796 $261,428 Depreciation, depletion and amortization expense on property, plant, and equipment was $29,811, $26,414, and $30,049 for the years ended December 31, 2023,December 31, 2022 and December 31, 2021, respectively. 6. OTHER NON-CURRENT ASSETS Other non-current assets consisted of the following at December 31: 2023 2022 Stores inventory, non-current $22,318 $22,353 Internal-use software, net of accumulated amortization 4,817 4,868 Other 1,200 4,266 Total $28,335 $31,487 During the years ended December 31, 2023, 2022 and 2021, in accordance with ASC 350-40, Internal Use Software, we capitalized $22, $38, and $869, respectively, ofcertain internal use software development costs. Software development activities generally consist of three stages (i) the research and planning stage, (ii) theapplication and infrastructure development stage, and (iii) the post-implementation stage. Costs incurred in the planning and post-implementation stages ofsoftware development, or other maintenance and development expenses that do not meet the qualification for capitalization are expensed as incurred. Costs incurredin the application and infrastructure development stage, including significant enhancements and upgrades, are capitalized. These software development costs areamortized on a straight-line basis over the estimated useful life of five to ten years under depreciation and amortization expense which is included in the cost ofproducts sold financial statement line item of the statements of operations and comprehensive income. During the years ended December 31, 2023, 2022 and 2021,we amortized internal use software development costs of $873, $862, and $853, respectively. At December 31, 2023 and 2022 internal-use software gross cost was$8,540 and $8,574, respectively and accumulated amortization was $3,723 and $3,706, respectively. Amortization for these internal use software development costs isexpected to be approximately $813 per year. 7. ACCRUED EXPENSES Accrued expenses consisted of the following at December 31: 2023 2022 Accrued capital expenditures $1,593 $1,596 Accrued employee compensation & benefits 10,749 11,302 Accrued energy costs 7,073 11,726 Accrued royalty costs 7,424 11,096 Accrued other taxes 5,195 5,361 Accrued derivatives fair value 7,541 7,921 Received not invoiced accruals 7,640 8,812 Other accruals 3,195 1,512 Total $50,410 $59,326 14 8. DEBT Long-term debt consisted of the following at December 31: 2023 2022 Sisecam Wyoming Equipment Financing Arrangement Security Note Number 001 with maturity date of March 26, 2028,fixed interest rate of 2.479% $18,358 $21,505 Sisecam Wyoming Equipment Financing Arrangement Security Note Number 002 with maturity date of December 17,2026, fixed interest rate of 2.4207% 17,819 23,477 Sisecam Wyoming Credit Facility, secured principal expiring on October 28, 2026, variable interest rate as a weightedaverage rate of 7.37% at December 31, 2023 77,000 92,000 Total debt 113,177 136,982 Less current portion of long-term debt 9,030 8,805 Total long-term debt $104,147 $128,177 Aggregate maturities required on long-term debt at December 31, 2023 are due in future years as follows: 2024 $9,060 2025 9,285 2026 86,515 2027 3,518 2028 4,893 Total $113,271 Sisecam Wyoming Equipment Financing Arrangement Master Loan and Security Agreement: On March 26, 2020, Sisecam Wyoming LLC and Banc of America Leasing & Capital, LLC, as lender (the “Equipment Financing Lender”), entered into an equipmentfinancing arrangement (“Sisecam Wyoming Equipment Financing Arrangement”), including a Master Loan and Security Agreement, dated as of March 25, 2020 (asamended, the “Master Agreement”) and an Equipment Security Note Number 001, dated as of March 25, 2020 (the “Sisecam Wyoming Equipment FinancingArrangement Security Note Number 001,” or the “Initial Secured Note”), which provides the terms and conditions for the debt financing of certain equipment relatedto the Company’s natural gas-fired turbine co-generation facility that became operational in March 2020. Each equipment financing entered into under the SisecamWyoming Equipment Financing Arrangement will be evidenced by the execution of one or more equipment notes (including the Initial Secured Note) thatincorporate the terms and conditions of the Master Agreement (each, an “Equipment Note”). In order to secure the payment and performance of the Company'sobligations under the Sisecam Wyoming Equipment Financing Arrangement, the Company granted to the Equipment Financing Lender a continuing securityinterest in all of the Company’s right, title and interest in and to the Equipment (as defined in the Master Agreement) and certain related collateral. On October 28, 2021, in connection with the entry into the Sisecam Wyoming Credit Facility (which replaced the Prior Sisecam Wyoming Credit Facility), theCompany and the Equipment Financing Lender entered into an amendment to the Master Agreement, in order to amend and restate all covenants that are basedupon a specified level or ratio relating to assets, liabilities, indebtedness, rentals, net worth, cash flow, earnings, profitability, or any other accounting-basedmeasurement or test to conform with the Sisecam Wyoming Credit Facility. On December 17, 2021, the Company and the Equipment Financing Lender entered into Amendment Number 001 to the Initial Secured Note (“First Amendment tothe Initial Secured Note”). The First Amendment to the Initial Secured Note, provides among other things: (i) upon the occurrence of an early full payoff of theSecond Secured Note (as defined below), the Company shall simultaneously pay, in full, the outstanding amount of the Initial Secured Note and (ii) the Companygrants to Equipment Financing Lender a security interest in all collateral securing the Second Secured Note to secure the Company’s obligations under the InitialSecured Note. At December 31, 2023, the Company was in compliance with all financial covenants of the Sisecam Wyoming Equipment Financing Arrangement. 15 The Sisecam Wyoming Equipment Financing Arrangement: (1) incorporates all covenants in the Sisecam Wyoming Credit Facility (as defined below), now or hereinafter existing, or in any applicable replacement credit facilityaccepted in writing by the Equipment Financing Lender, that are based upon a specified level or ratio relating to assets, liabilities, indebtedness, rentals, net worth,cash flow, earnings, profitability, or any other accounting-based measurement or test, and (2) includes customary events of default subject to applicable graceperiods, including, among others, (i) payment defaults, (ii) certain mergers or changes in control of the Company, (iii) cross defaults with certain other indebtedness(a) to which the Equipment Financing Lender is a party or (b) to third parties in excess of $10,000, and (iv) the commencement of certain insolvency proceedings orrelated events identified in the Master Agreement. Upon the occurrence of an event of default, in its discretion, the Equipment Financing Lender may exercisecertain remedies, including, among others, the ability to accelerate the maturity of any Equipment Note such that all amounts thereunder will become immediatelydue and payable, to take possession of the Equipment identified in any Equipment Note, and to charge the Company a default rate of interest on all thenoutstanding or thereafter incurred obligations under the Sisecam Wyoming Equipment Financing Arrangement: Among other things, Security Note Number 001: •was executed on March 25, 2020; •has a principal amount of $30,000; •has a maturity date of March 26, 2028; •shall be payable by the Company to the Equipment Financing Lender in 96 consecutive monthly installments of principal and interest commencing on April26, 2020 and continuing thereafter until the maturity date of the Initial Secured Note, which shall be in the amount of approximately $307 for the first 95monthly installments and approximately $4,307 for the final monthly installment; and •entitles the Company to prepay all (but not less than all) of the outstanding principal balance of the Initial Secured Note (together with all accrued interestand other charges and amounts owed thereunder) at any time after one (1) year from the date of the Initial Secured Note, subject to the Company paying tothe Equipment Financing Lender an additional prepayment amount determined by the amount of principal balance prepaid and the date such prepayment ismade. In connection with the Second Sisecam Wyoming Amendment (as defined below), the Master Agreement was amended to incorporate, among other things, themodified covenants set forth in the Second Sisecam Wyoming Amendment related to consolidated leverage ratios of Sisecam Wyoming. In December 2021 a waiver was obtained to accommodate the Sisecam USA acquisition of control of Sisecam Chemicals from Ciner Enterprises (the "CoCTransaction"). First Amendment to Security Note Number 001: On December 17, 2021, the Company and the Equipment Financing Lender entered into Amendment Number 001 to the Initial Secured Note (“First Amendment tothe Initial Secured Note”). The First Amendment to the Initial Secured Note, provides among other things: (i) upon the occurrence of an early full payoff of theSecond Secured Note, (as defined below), the Company shall simultaneously pay, in full the outstanding amount of the Initial Secured Note and (ii) the Companygrants to Equipment Financing Lender a security interest in all collateral securing the Second Secured Note to secure the Company’s obligations under the InitialSecured Note. The Company’s balance under the Sisecam Wyoming Equipment Financing Arrangement at December 31, 2023 was $18,452 ($18,358 net of financing costs). AtDecember 31, 2023 the effective interest rate was 2.718%. Among other things, Security Note Number 002: •was executed on December 17, 2021; •has a principal amount of $29,000; •has a maturity date of December 17, 2026; •shall be payable by Sisecam Wyoming to the Equipment Financing Lender in 60 consecutive monthly installments of principal and interest commencing onJanuary 17, 2022 and continuing thereafter until the maturity date of the Second Secured Note, which shall be in the amount of approximately $514 for eachmonthly installment; •entitles Sisecam Wyoming to prepay all (but not less than all) of the outstanding principal balance of the Second Secured Note (together with all accruedinterest and other charges and amounts owed thereunder) at any time after one (1) year from the date of the Second Secured Note, subject to SisecamWyoming paying to the Equipment Financing Lender an additional prepayment amount determined by the amount of principal balance prepaid and thedate such prepayment is made and subject to Sisecam Wyoming simultaneously paying, in full, the outstanding amount of the Initial Secured Note asdiscussed above; and •upon the occurrence of full payoff of Initial Secured Note dated as of March 25, 2020 under the Master Agreement, Sisecam Wyoming shall simultaneouslypay, in full, the outstanding amount of this Second Secured Note. 16 Sisecam Wyoming Credit Facility On October 28, 2021, the Company entered into a new $225,000 senior secured revolving credit facility (the “Sisecam Wyoming Credit Facility”) with each of thelenders listed on the respective signature pages thereof and Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer. TheSisecam Wyoming Credit Facility matures on October 28, 2026. On closing, the amount drawn under this new Sisecam Wyoming Credit Facility approximated theamount outstanding under the Prior Sisecam Wyoming Credit Facility at September 30, 2021. The Sisecam Wyoming Credit Facility provides, among other things: •a sublimit up to $40,000 for the issuance of standby letters of credit and a sublimit up to $20,000 for swingline loans; •an accordion feature that enables the Company to increase the revolving borrowings under the Sisecam Wyoming Credit Facility by up to an additional$250,000 (subject to certain conditions); •in addition to the aforementioned revolving borrowings, an ability to incur up to $225,000 of additional term loan facility indebtedness to finance theCompany's capacity expansion capital expenditures; (subject to certain conditions); •a pledge by the Company of substantially all of the Company’s assets (subject to certain exceptions), including: (i) all present and future shares of anysubsidiaries of the Company (whether now existing or hereafter created) and (ii) all personal property of the Company (subject to certain conditions); •contains various covenants and restrictive provisions that limit (subject to certain exceptions) the Company’s ability to: (i) incur certain liens or permitthem to exist; (ii) incur or guarantee additional indebtedness; (iii) make certain investments and acquisitions related to the Company’s operations inWyoming); (iv) merge or consolidate with another company; (v) transfer, sell or otherwise dispose of assets, (vi) make distributions; (vii) change the natureof the Company’s business; and (viii) enter into certain transactions with affiliates; •a requirement to maintain a quarterly consolidated leverage ratio of not more than 3.25:1:00; provided, however, subject to certain conditions, theCompany shall have the ability to increase the maximum consolidated leverage ratio to 3.75:1.00 for a year while the Company is undertaking capacityexpansion capital expenditures; •a requirement to maintain a quarterly consolidated interest coverage ratio of not less than 3.00:1.00; and •customary events of default including (i) failure to make payments required under the Sisecam Wyoming Credit Facility, (ii) events of default resulting fromfailure to comply with covenants and financial ratios, (iii) the occurrence of a voluntary change of control, as a result of which the Company is directly orindirectly controlled by persons or entities not currently directly or indirectly controlling the Company, (iv) the institution of insolvency or similarproceedings against the Company, and (v) the occurrence of a cross default under any other material indebtedness the Company may have. Upon theoccurrence of an event of default, in their discretion, the Sisecam Wyoming Credit Facility lenders may exercise certain remedies, including, among others,accelerating the maturity of any outstanding loans, accrued and unpaid interest and all other amounts owing and payable such that all amounts thereunderwill become immediately due and payable, and if not timely paid upon such acceleration, to charge Sisecam Wyoming a default rate of interest on allamounts outstanding under the Sisecam Wyoming Credit Facility. However, upon the occurrence of an involuntary change of control of SisecamWyoming, and after the passage of time as specified in the Sisecam Wyoming Credit Facility, the Company’s debt thereunder would be accelerated. In addition, loans under the Sisecam Wyoming Credit Facility (other than any swingline loans) will bear interest at the Company's option at either: •a base rate, which equals the highest of (i) Bank of America’s prime rate, (ii) the federal funds rate then in effect on such day, plus 0.50%; (iii) one-monthBloomberg Short-Term Bank Yield Index (“BSBY”) adjusted daily rate, plus 1.0%; and (iv) 1.0%, plus, in each case, an applicable margin range from 0.50%to 1.75% based on the consolidated leverage ratio of Sisecam Wyoming; or •a BSBY rate for interest periods of one, three or six months, plus, in each case, an applicable margin range from 1.50% to 2.75% based on the consolidatedleverage ratio of Sisecam Wyoming. 17 In addition, if a BSBY rate ceases to exist for any period, loans under the Sisecam Wyoming Credit Facility will bear interest based on alternative indexes (includingthe secured overnight financing rate), plus an applicable margin. The unused portion of the Sisecam Wyoming Credit Facility is subject to a per annum commitment fee and the applicable margin of the interest rate under theSisecam Wyoming Credit Facility will be determined as follows: Pricing Tier Leverage Ratio BSBY Rate Loans Base Rate Loans Commitment Fee 1 < 1.25:1.0 1.50% 0.50% 0.23% 2 ≥ 1.25:1.0 but < 1.75:1.0 1.75% 0.75% 0.25% 3 ≥ 1.75:1.0 but < 2.25:1.0 2.00% 1.00% 0.28% 4 ≥ 2.25:1.0 but < 3.00:1.0 2.25% 1.25% 0.30% 5 ≥ 3.00:1.0 but < 3.50:1.0 2.50% 1.50% 0.33% 6 ≥ 3.50:1.0 2.75% 1.75% 0.35% The Sisecam Wyoming Credit Facility permits the consolidated leverage ratio as of the end of each fiscal quarter of Sisecam Wyoming, commencing with the fiscalquarter ending December 31, 2021, to be greater than 3.25: 1.00; provided, however, during the Specified Capital Expansion Holiday, the lenders shall not permit theconsolidated leverage ratio as of the end of each fiscal quarter of the Company to be greater than 3.75:1.00. “Specified Capital Expansion Holiday” means the periodconsisting of four (4) full fiscal quarters after the Company has (i) made capital expenditures related to the Specified Capital Expansion (or other capital expansionproject approved by the board of directors, board of managers or equivalent governing body of the Company) of at least $200,000 and (ii) provided written notice tothe administration that the Company is electing to initiate such Specified Capital Expansion Holiday. “Specified Capital Expansion” means expansion activitiesrelated to the lenders’ soda ash operations in Wyoming which have been approved in writing by the Company’s board of directors, board of managers or equivalentgoverning body. The Sisecam Wyoming Credit Facility permits the consolidated interest coverage ratio as of the end of any fiscal quarter of the Company, commencing with the fiscal quarter ending December 31, 2021, to be less than 3.00:1.00. In connection with the CoC Transaction (as defined above), on December 17, 2021, Sisecam Wyoming entered into the First Amendment (“First Amendment”) to its$225,000 senior secured revolving credit facility, dated as of October 28, 2021 (as amended, the “Sisecam Wyoming Credit Facility”), with each of the lenders listedon the respective signature pages thereof and Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer. Pursuant to the FirstAmendment, the definition of “Change of Control” under the Credit Facility was revised to reflect that the updated indirect ownership of Sisecam Resource LP andSisecam GP as contemplated by the CoC Transaction will not cause a Change of Control under the Sisecam Wyoming Credit Facility so long as the CoC Transactionoccurred prior to March 31, 2022. The CoC Transaction did not cause a change in control event under the Credit Facility. Management is not aware of any current circumstances that would result in an event of default under the Sisecam Wyoming Credit Facility at December 31, 2023 orin the next twelve months. 9. OTHER NON-CURRENT LIABILITIES Other non-current liabilities consisted of the following at December 31: 2023 2022 Asset retirement obligations $8,901 $8,434 Derivative instruments and hedges, fair value and other liabilities 17 595 Accrued non-income tax related taxes 6,468 7,084 Total $15,386 $16,113 Details of the asset retirement obligations reserve shown above are as follows: 2023 2022 Asset retirement obligations reserve at beginning of year $8,434 $7,993 Accretion expense 467 441 Asset retirement obligations reserve at end of year $8,901 $8,434 At December 31, 2023 and 2022 the undiscounted asset retirement obligations were approximately $44,745 and $46,235, respectively. 18 10. EMPLOYEE BENEFIT PLANS The Company participates in various benefit plans offered and administered by Sisecam Chemicals and is allocated its portions of the annual costs related thereto.The specific plans are as follows: Retirement Plans - Benefits provided under the retirement plans for salaried employees and hourly employees (the “Retirement Plans”) are based upon years ofservice and average compensation for the highest 60 consecutive months of the employee’s last 120 months of service, as defined. The Retirement Plans coversubstantially all full-time employees hired before May 1, 2001. Sisecam Chemicals’ Retirement Plans had a net liability balance of $20,951 and $26,576 at December31, 2023 and December 31, 2022, respectively. Sisecam Chemicals’ current funding policy is to contribute an amount within the range of the minimum required andthe maximum tax-deductible contribution. The Company’s allocated portion of the Retirement Plans’ net periodic pension cost (benefit) for the years endedDecember 31, 2023, 2022 and 2021 was $478, $(3,705) and $(2,723), respectively. Savings Plan -The 401(k) retirement plan (the “401(k) Plan”) covers all eligible hourly and salaried employees. Eligibility is limited to all domestic residents and anyforeign expatriates who are in the United States indefinitely. The 401(k) Plan permits employees to contribute specified percentages of their compensation, while theCompany makes contributions based upon specified percentages of employee contributions. Participants hired on or subsequent to May 1, 2001, will receive anadditional contribution from the Company based on a percentage of the participant’s base pay. Contributions made to the 401(k) Plan for the years ended December31, 2023, 2022, and 2021 were $3,999, $3,604, and $3,356, respectively. Postretirement Benefits - Most of the Company’s employees hired before January 2, 2017 are eligible for postretirement benefits other than pensions if they reachage 58 while still employed with at least 10 years of service. The postretirement benefits are accounted for by Sisecam Chemicals on an accrual basis over an employee’s period of service. The postretirement plan, excludingpensions, is not funded, and Sisecam Chemicals has the right to modify or terminate the plan. The post-retirement plan had a net unfunded liability of $6,783 and$7,652 on December 31, 2023 and December 31, 2022, respectively. The Company’s allocated portion of postretirement cost for the years ended December 31, 2023, 2022, and 2021, was $437, $713, and $871, respectively. 11. ACCUMULATED OTHER COMPREHENSIVE (LOSS)/INCOME Accumulated other comprehensive (loss)/income as of December 31, 2023, 2022, and 2021 consisted of the following: Interest Rate SwapContracts Financial Gas SwapContracts Total BALANCE at January 1, 2021 $(1,273) $1,345 $72 Other comprehensive income before reclassification 205 5,692 5,897 Amounts reclassified from accumulated other comprehensive income 702 (702) — Net current-period other comprehensive (loss)/income 907 4,990 5,897 BALANCE at December 31, 2021 $(366) $6,335 $5,969 Other comprehensive income before reclassification 1,249 44,215 45,464 Amounts reclassified from accumulated other comprehensive income/(loss) 262 (14,082) (13,820)Net current-period other comprehensive income 1,511 30,133 31,644 BALANCE at December 31, 2022 $1,145 $36,468 $37,613 Other comprehensive income before reclassification 112 (8.155) (8,043)Amounts reclassified from accumulated other comprehensive income/(loss) (942) (35,585) (36,527)Net current-period other comprehensive income (830) (43,740) (44,570)BALANCE at December 31, 2023 $315 $(7,272) $(6,957) The components of other comprehensive income/(loss), that have been reclassified out of accumulated other comprehensive income/loss consisted of thefollowing: 2023 2022 2021 Affected Line Items on the Statements ofOperations and Comprehensive IncomeDetails about other comprehensive income/(loss) components: Gains/(losses) on cash flow hedges: Interest rate swap contracts $(942) $262 $702 Interest expenseFinancial gas swap contracts (35,585) (14,082) (702)Cost of products soldTotal reclassifications for the period $(36,527) $(13,820) $— 19 12. COMMITMENTS AND CONTINGENCIES Lease and License Commitments The Company leases and licenses mineral rights from the U.S. Bureau of Land Management, the state of Wyoming, Sweetwater Royalties, LLC, a subsidiary ofSweetwater Trona OpCo LLC and the successor in interest to the license to the Rock Springs Royalty Company, LLC (“RSRC”), an affiliate of Occidental PetroleumCorporation (formerly an affiliate of Anadarko Petroleum Corporation), and other private parties which provide for royalties based upon production volume. TheCompany has a perpetual right of first refusal with respect to these leases and license and intends to continue renewing the leases and license as has been itspractice. Sisecam Chemicals enters into contracts with one railroad company for the majority of the domestic rail freight services that the Company receives and the relatedfreight and logistics costs are allocated to the Company. For the years ended December 31, 2023 and 2022, the Company shipped over 90% of our soda ash to ourcustomers initially via a single rail line owned and controlled by the railroad company. If Sisecam Chemicals does not ship at least a significant portion of our sodaash production on the railroad company’s rail line during a twelve-month period, it must pay the railroad company a shortfall payment under the terms of ourtransportation agreement. The Company assists the majority of its domestic customers in arranging their freight services. During the years ended December 31,2023 and 2022, Sisecam Chemicals had no shortfall payments and does not expect to make any such payments in the future. Sisecam Chemicals renewed itsagreement with the railroad company in October 2021, which expires on December 31, 2025. As of December 31, 2023, the total minimum contractual rental commitments under the Company’s various operating leases, including renewal periods isapproximately $1,911 with the amount due in any of the next five years being immaterial. Sisecam Chemicals typically enters into operating lease contracts with various lessors for rail cars to transport product to customer locations and warehouses. Railcar leases under these contractual commitments range for periods from one to ten years. Sisecam Chemicals’ obligation related to these rail car leases are $14,613 in2024, $13,253 in 2025, $12,021 in 2026, $8,777 in 2027 and $6,347 thereafter. Total lease expense allocated to the Company from Sisecam Chemicals was approximately$17,113, $10,996, and $10,583 for the years ended December 31, 2023, 2022 and 2021, respectively and is recorded in cost of products sold. Purchase Commitments - We have financial gas swap contracts to mitigate volatility in the price of natural gas. As of December 31, 2023, these contracts' aggregatenotional value totaled approximately $22,778 for the purchase of a portion of the Company’s natural gas requirements for the following year. The Company has aseparate contract through 2031 for the transportation of natural gas with an average minimum annual cost of approximately $1,500 per year. Legal and Environmental Matters- From time to time we are party to various claims and legal proceedings related to our business. Although the outcome of theseproceedings cannot be predicted with certainty, management does not currently expect any such legal proceedings we may be involved in from time to time to havea material effect on our business, financial condition and results of operations. We cannot predict the nature of any future claims or proceedings, nor the ultimatesize or outcome of any such claims and legal proceedings and whether any damages resulting from them will be covered by insurance. Mine Permit Bonding Commitment - Our operations are subject to oversight by the Land Quality Division of Wyoming Department of Environmental Quality(“WDEQ”). Our principal mine permit issued by the Land Quality Division, requires the Company to provide financial assurances for our reclamation obligations forthe estimated future cost to reclaim the area of our processing facility, surface pond complex and on-site sanitary landfill. The Company provides such assurancesthrough a third-party surety bond (the “Surety Bond”). The Surety Bond amount was $41,814 on December 31, 2023 and 2022. 20 13. AGREEMENTS AND TRANSACTIONS WITH AFFILIATES Agreements and transactions with affiliates have a significant impact on the Company’s financial statements because the Company is a subsidiary and investeewithin two different global group structures. Agreements directly between the Company and other affiliates, or indirectly between affiliates that the Company doesnot control, can have a significant impact on recorded amounts or disclosures in the Company's financial statements, including any commitments and contingenciesbetween the Company and affiliates, or potentially, third parties. Sales-affiliates are sales that aligned with the Company’s foreign market penetration and logistics cost strategies. Cost of goods sold-affiliates primarily consists oflogistic services. Selling, general and administrative expenses also include amounts charged to the Company by its affiliates principally consisting of salaries, benefits, officesupplies, professional fees, travel, rent and other costs of certain assets used by the Company. Sisecam Chemicals provides the Company with certain corporate,selling, marketing and general and administrative services, in return for which the Company has agreed to pay Sisecam Chemicals an annual management fee andreimburse Sisecam Chemicals for certain third-party costs incurred in connection with providing such services. In addition, under the limited liability companyagreement governing Sisecam Wyoming, Sisecam Wyoming reimburses Sisecam Chemicals for employees who operate Sisecam Chemical’s assets and for supportprovided to Sisecam Wyoming. These transactions with affiliates do not necessarily represent arm's length transactions and may not represent all costs if Sisecam Wyoming operated on astandalone basis. The total selling, general and administrative costs charged to the Company by affiliates for the years ended December 31, 2023, 2022 and 2021 were as follows: 2023 2022 2021 Sisecam Chemicals $20,753 $19,016 $16,494 Other — 245 141 Total selling, general and administrative expenses - affiliates $20,753 $19,261 $16,635 As of December 31, 2023 and 2022, the Company had due from/to with affiliates as follows: 2023 2022 Accounts receivable -affiliates Due to affiliates Accounts receivable -affiliates Due to affiliates Sisecam Chemicals (1) $53,759 $2,881 $53,862 $3,408 Other 1,412 2,001 62 2,653 Total $55,171 $4,882 $53,924 $6,061 (1) Accounts receivable from Sisecam Chemicals is primarily related to the timing of funding for the pension and postretirement plans offered and administered bySisecam Chemicals. 14. SEGMENT REPORTING Our operations are similar in geography, nature of products we provide, and type of customers we serve. As the Company earns substantially all of its revenuesthrough the sale of soda ash mined at a single location, we have concluded that we have one operating segment for reporting purposes. The net sales by geographic area for the years ended December 31, 2023, 2022 and 2021 were as follows: 2023 2022 2021 Domestic $345,647 $304,994 $276,778 International 427,943 415,126 263,361 Total net sales $773,590 $720,120 $540,139 The Company had no customers for the year ended December 31, 2023 that individually represented over 10% of net sales and two major international customers forthe year ended December 31, 2022 and 2021, which individually account for over 10% of net sales. Revenues from these customers were $188,162 for the year endedDecember 31, 2022 and $173,000 for the year ended December 31, 2021. The Company had two customers whose outstanding balance individually represented over10% of accounts receivable with combined accounts receivable balance of $39,788 and $45,917 at December 31, 2023 and December 31, 2022, respectively. 15. SUBSEQUENT EVENTS Cash Distribution On February 1, 2024, the members of the board of managers of Sisecam Wyoming, approved a cash distribution to the members of Sisecam Wyoming in theaggregate amount of $29,000. This distribution was paid on February 2, 2024. ****** 21Unitholder Information Partnership Headquarters 1415 Louisiana Street, Website www.nrplp.com Suite 3325 Houston, TX 77002 (713) 751-7507 Regional Office Mineral Rights 5260 Irwin Road Huntington, WV 25705 Investor Relations Tiffany Sammis 1415 Louisiana Street, Suite 3325 Houston, TX 77002 (713) 751-7515 email: info@nrplp.com Stock Exchange Our units are listed on the New York Stock Exchange under the symbol NRP Independent Auditors Ernst & Young LLP 5 Houston Center 1401 McKinney, Suite 2400 Houston, TX 77010 Transfer Agent and Registrar Equiniti Trust Company, LLC 55 Challenger Road Ridgefield Park, NJ 07660 Website: www.equiniti.com Email: helpast@equiniti.com (800) 937-5449 Information regarding Natural Resource Partners L.P. is located on the partnership’s website. On the site is operational and financial information as well as all SEC filings and our corporate governance documents, including our Code of Business Conduct and Ethics, our Corporate Governance Guidelines and Board of Directors’ Audit Committee Charter. Requests for copies of the annual report or other data may be made through the website or by contacting Investor Relations. These requests will be provided free of charge. Contact NRP Board We have established procedures for contacting the non-management members of the NRP Board of Directors. To communicate any concerns or issues to the Board of Directors, please direct any correspondence to: Chairman of the CNG Committee NRP Board of Directors 1415 Louisiana Street, Suite 3325 Houston, TX 77002 888-252-2396 Schedule K-1 and Schedule K-3 Unitholders receive Schedule K-1 packages that summarize their allocated share of the partnership’s reportable tax items for the calendar year. Generally, these K-1s are available on NRP’s website no later than mid-March. A limited number of unitholders (primarily foreign unitholders, unitholders computing a foreign tax credit on their tax return and certain corporate and/or partnership unitholders) may need the detailed information disclosed on Schedule K-3 for their specific reporting requirements, which are generally available on NRP’s website no later than June. Unitholders should refer questions regarding their Schedule K-1 and Schedule K-3 to the following: Natural Resource Partners L.P. Tax Package Support P.O. Box 139031 Dallas, TX 75313 Toll Free: 1-888-334-7102 Forward-Looking Statements Statements included in this annual report may constitute forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding: future distributions on our common and preferred units; our business strategy; our liquidity and access to capital and financing sources; our financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projected production levels by our lessees; Sisecam Wyoming LLC’s ("Sisecam Wyoming's") trona mining and soda ash refinery operations; distributions from our soda ash joint venture; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and global and U.S. economic conditions. 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. Please read “Item 1A. Risk Factors” of the Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to differ. NRPNatural Resource Partners L.P.1415 Louisiana Street, Suite 3325Houston, Texas 77002www.nrplp.comAnnual Report2023

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