NATURAL RESOURCE PARTNERS LP 10-K

nrp20221231_10k.htm     Table of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 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, 2022 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)         Delaware 35-2164875 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 1415 Louisiana Street, Suite 3325 Houston , 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 registered Common 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 the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes   ☒        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 growth company. See definition of "accelerated filer", "large accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. 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 revised financial 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 over financial 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 the correction 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 of the 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, 2022, was $ 334  million based on a closing price on that date of $37.23 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 Statements ii Risk Factors Summary ii PART I Items 1. and 2. Business and Properties 1 Item 1A. Risk Factors 15 Item 1B. Unresolved Staff Comments 26 Item 3. Legal Proceedings 26 Item 4. Mine Safety Disclosures 26   PART II Item 5. Market for Registrant ’ s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities 27 Item 6. [RESERVED] 27 Item 7. Management ’ s Discussion and Analysis of Financial Condition and Results of Operations 27 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 39 Item 8. Financial Statements and Supplementary Data 40 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 72 Item 9A. Controls and Procedures 72 Item 9B. Other Information 74   PART III Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance 75 Item 11. Executive Compensation 80 Item 12. Security Ownership of Certain Beneficial Owners and Management 83 Item 13. Certain Relationships and Related Transactions, and Director Independence 85 Item 14. Principal Accountant Fees and Services 90   PART IV Item 15. Exhibits, Financial Statement Schedules 92 Signatures   96   i Table of Contents   CAUTIONARY STATEMENT REGARDING 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 or written statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding: the effects of the global COVID-19 pandemic; 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"), formerly known as Ciner Wyoming, 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 our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should not put undue reliance on any forward-looking statements. See " Item 1A. Risk Factors " in this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to 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 stock and certain general risks, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Risks that we deem material 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 our partnership 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. • The ongoing COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and ability to make cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted. • 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 adverse effect 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 to make 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 of operations. • 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 changes in 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 and investment 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 that may 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 and capital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture and through our ownership of certain coal transportation assets. • Sisecam Wyoming’s deca stockpiles will substantially deplete by 2024, and its production rates will decline approximately 200,000 short tons per year if Sisecam Wyoming does not make further investments or 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 our properties. • 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 of minimum 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 be identified 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 our debt 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-level taxation 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 become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced. • The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing 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 of our 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 of properties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions made with respect 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 our cash available for distribution to our unitholders. • If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, 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 this treatment, 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 these methodologies 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 the ownership 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 this treatment, 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 of those 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 may recognize 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 own or 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, financial condition, results of operations, and cash flows.   iv Table of Contents     PART I   As used in this Part I, 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 its subsidiaries. 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 and soda 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, as well as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energy economy 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 Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries.   Our operations are conducted through Opco and our operating assets are owned by our subsidiaries. NRP (GP) LP, our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations and the Board of Directors and officers of GP Natural Resource Partners LLC make decisions on our behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Subject to the Board Representation and Observation Rights Agreement 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"), Mr. Robertson, Jr. is entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC and has delegated the right to appoint one director to Blackstone.   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, but they 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 the telephone 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.     1 Table of Contents   Segment and Geographic Information   The amount of 2022 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 and Supplementary Data—Note 7. Segment Information " in this Annual Report on Form 10-K, which are both incorporated herein by reference.   (In thousands)   Amount     % of Total   Mineral Rights   $ 329,167       85 % Soda Ash     59,795       15 % Total   $ 388,962       100 %   The following map shows the approximate geographic distribution of our ownership footprint:       Table 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 of royalties 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 typically supported 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 the Appalachia 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 for additional terms. Leases include the right to renegotiate royalties and minimum payments for the additional terms. We also own and manage coal-related transportation and processing assets in the Illinois Basin that generate additional revenues generally based on throughput or rents. We also own oil and gas, industrial minerals and aggregates that generate a portion of the Mineral Rights segment revenues. Additional Mineral Rights segment revenues come from carbon neutral initiatives such the sale of carbon offset credits from our forestlands, potential sub-surface carbon dioxide sequestration in our pore space and opportunities to generate geothermal energy from 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 a percentage 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 minerals mined 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 our lessees. We periodically audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify that the 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 well as 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 mining activity occurs during the period. Minimum payments are usually credited against future royalties that are earned as minerals are produced. In certain leases, the lessee is 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 labor risks. Our lessees, as operators, are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. In addition, the lessees generally bear all labor-related risks, including retiree health care costs, black lung benefits and workers’ compensation costs associated with operating 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 terms of 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 we comply 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 to and cannot obtain without incurring an unreasonable burden or expense. As a royalty company, we do not have access to the information required to prepare the technical reports used to determine reserves under the rules, and we are not able to obtain such information without unreasonable burden or expense. The rules require that reserve estimates be based on and disclosures include technical reports prepared using extensive mine-specific geological and engineering data, as well as market and 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 of environmental compliance and permitting requirements; d) detailed baseline studies with impact assessment; and e) detailed tailings disposal, reclamation and mitigation plans. Our leases do not require the operators of our material properties to prepare technical report summaries or permit us the access and information sufficient to prepare 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 other hard mineral reserves.   In addition to summary information about our overall portfolio of mineral rights, this section provides detailed information about four properties in our Mineral Rights segment. These properties were determined to be material to our business based on historical revenue compared to our Mineral Rights segment considered as a whole. 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, cleaner coal that generates exceptionally high temperatures when burned and is an essential element in the steel manufacturing process. Metallurgical coal is a finite and declining resource, particularly in industrialized nations. We believe the indispensable role met coal plays in manufacturing steel combined with the increasing scarcity of 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 Southern Appalachian 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 been steadily 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 such as 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 the long-term strength of our metallurgical business and the carbon neutral initiatives we discuss below, will result in thermal coal becoming a diminishing contributor to NRP 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 Mississippi River. The remainder of our thermal coal is located in Montana, the Gulf Coast and Appalachia.   2 Table 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, 2022, 2021 and 2020:   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     For the Year Ended December 31, 2020       Type of Coal           (Tons in thousands)   Thermal     Metallurgical     Total   Appalachia Basin                         Northern     267       380       647   Central     1,157       8,954       10,111   Southern     143       746       889   Total Appalachia Basin     1,567       10,080       11,647   Illinois Basin     3,381       —       3,381   Northern Powder River Basin     1,738       —       1,738   Total     6,686       10,080       16,766       Major Coal Producing Properties   The following table provides a summary of our significant coal royalty properties for 2022 and is followed by additional information for each property:   Region   Property/Lease Name   Operator(s)   Coal Type Appalachia Basin             Northern   Carter Roag   Metinvest   Met Central   Alpha-CAPP (VA)   Alpha Metallurgical Resources Inc.   Met Central   Kepler   Alpha Metallurgical Resources Inc.   Met Central   Elk Creek   Ramaco Royalty Company, LLC   Met Central   Coal Mountain   ECP   Met Southern   Oak Grove   Hatfield Metallurgical Coal Holdings, LLC   Met Illinois Basin   Williamson   Foresight Energy Resources LLC   Thermal Illinois Basin   Hillsboro   Foresight Energy Resources LLC   Thermal Northern Powder River Basin   Western Energy   Rosebud Mining, LLC   Thermal   3 Table of Contents   Appalachia Basin — Northern Appalachia   Carter Roag.     The Carter Roag property is located in Randolph and Upshur counties, West Virginia. Substantially all of the tons sold from this property in 2022 were metallurgical coal. We lease this property to subsidiaries of Metinvest. Production comes from underground room and pillar mines, is processed onsite at the Star Bridge Prep Plant, and is sold primarily on the export market.   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 sold from this property in 2022 were metallurgical coal. We lease this property to subsidiaries of Alpha Metallurgical Resources Inc. ("Alpha") and previously leased it to subsidiaries of Contura Energy, Inc. The current lease with Alpha expires at the end of 2023 and will automatically renew unless otherwise notified. We receive payments based 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 to minimum payments, which reflect 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 as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Production comes from underground 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 utility and metallurgical customers. The book value of this property was $47.2 million at December 31, 2022.   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. Metallurgical coal 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 to both 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 a multi-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 and export metallurgical customers.   Kepler .    The Kepler property is located in Wyoming County, West Virginia. Substantially all of the coal sold from this property in 2022 were metallurgical coal. We lease 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 is shipped via the Norfolk Southern railroad to export metallurgical customers.   4 Table 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 Coal Holdings, 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 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 to minimum payments, which reflect 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 as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Metallurgical coal production comes from a longwall mine and is transported by beltline to a preparation plant. Metallurgical products are then shipped via railroad and barge to both domestic and export customers. The book value of this property was $4.6 million at December 31, 2022.   Below is a map of our Oak Grove property:   5 Table 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 of Foresight Energy Resources LLC ("Foresight"). The current leases expire in 2026 and 2033 and will automatically renew unless otherwise notified. We receive payments based 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 to minimum payments, which reflect 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 as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Thermal coal production comes from a longwall mine. Coal is shipped primarily via the Canadian National railroad to export customers. The book value of this property was $40.2 million at December 31, 2022.   Below is a map of our Williamson property:   6 Table of Contents   Hillsboro.     The Hillsboro property is located in Montgomery and Bond Counties, Illinois. This property is under lease to Hillsboro Energy, a subsidiary of Foresight. 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 sale price 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 reflect amounts 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 via either the Union Pacific, Norfolk Southern or Canadian National railroads, or by barges to domestic utilities customers. The book value of this property was $215.8 million at December 31, 2022.   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 also operated 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, or quarterly minimum payments to us under the Macoupin coal mining lease and transportation agreements. Foresight will pay an annual Macoupin fee of $2.0 million to NRP each year through 2023. Foresight also forfeited its right to recoup all previously paid but unrecouped minimum payments with respect to the Macoupin mine. At all times that the Macoupin mine remains in temporary cessation of production, Foresight will take reasonable actions to preserve, protect, and store the equipment, infrastructure, and property located at the mine.   Beginning January 1, 2024, we may at any time elect to cause Foresight to transfer the Macoupin mine and all associated equipment and permits to us for no consideration. If we make this election, we will assume all liabilities associated with the Macoupin mine. Also beginning January 1, 2024, Foresight may at any time elect to 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 accept Foresight’s offer, Foresight may proceed to permanently seal the Macoupin mine and conduct all reclamation activities. To the extent the elections described above are not 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, Foresight may 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 mining lease and transportation agreements.   7 Table 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 Rosebud Mining, LLC. Thermal coal is produced by surface dragline mining methods. Coal is transported by either truck or beltline to the Colstrip generation station located at the 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's Williamson mine in the Illinois Basin, for which we collect throughput fees or rents. We lease our Williamson transportation and processing infrastructure to a subsidiary of Foresight and are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we subcontract to a subsidiary of Foresight. 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 Foresight and we collect minimums and throughput fees. We recorded $21.1  million in revenue related to our coal transportation and processing assets during the year ended December 31, 2022 .    We also own transportation and processing infrastructure, including loadout and other transportation assets at Foresight's Macoupin mine. As previously mentioned, the Macoupin mine was temporarily ceased in March 2020 and Foresight is no longer obligated to make transportation fee payments to us under the transportation agreements.   Oil and Gas / Industrial Minerals / Construction Aggregates / Timber   Our oil and gas properties are predominately located in Louisiana. Our various industrial mineral and construction aggregates properties are located across the United States and include minerals such as limestone, frac sand, lithium, copper, lead and zinc. We lease a portion 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 require minimum rental payments in addition to royalties. During 2022, we received $3.3  million i n aggregates royalty revenues, including overriding royalty revenues. We also own forest assets, primarily in West Virginia, which generate revenues from the forestland through carbon offset credits and timber sales.   Carbon Neutral Initiatives   We continue to identify alternative revenue sources across our large portfolio of land and mineral assets. The types of opportunities include the sequestration of carbon dioxide ("CO 2 ") underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy. As with our existing mineral activities, we do not plan to develop or operate carbon sequestration or carbon neutral energy projects ourselves but 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 and likelihood of additional cash flows being realized from these activities is uncertain, we believe our large ownership footprint throughout the United States will provide additional 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 credits were 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 approximately 39,000 acres of our forestland in West Virginia.   Carbon Sequestration. We own approximately 3.5 million acres of specifically reserved subsurface rights in the southern United States with the potential for permanent sequestration of greenhouse gases. The carbon capture utilization and storage industry (“CCUS”) is in its infancy and the future is highly uncertain, but a few facts are clear. A sequestration project requires acreage possessing unique geologic characteristics, close proximity to sources of industrial-scale greenhouse gas emissions, and the appropriate form of legal title that grants the acreage owner the right to sequester emissions in the subsurface. While carbon sequestration rights and ownership continue to evolve, we believe we own one of the largest inventory of acreage with potential for carbon sequestration activities in the United States.   In the first quarter of 2022 we executed our first subsurface CO 2  sequestration lease on 75,000 acres of underground pore space we own in southwest Alabama with the potential to store over 300 million metric tons of CO 2 . In October of 2022, we announced our second subsurface CO 2  transaction with the execution of a lease for approximately 65,000 acres of pore space we control near southeast Texas with estimated storage capacity of at least 500 million metric tons of CO 2 . In total, we have approximately 140,000 acres of pore space under lease for carbon sequestration with estimated CO 2  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 locations necessary for geothermal, solar and wind energy development. With regards to geothermal, the technology to generate safe and reliable “green” electricity using heat found deep underground is advancing rapidly. Once limited to the geologic “hot spots,” new technology has made geothermal energy projects feasible in many places previously thought impossible. Our geothermal opportunities are predominately located in the South, Midwest and Northwest parts of the United States. In the third quarter 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 energy opportunities, we are actively engaged in discussions for potential use of our acreage for these types of renewable energy developments predominantly in Kentucky and West Virginia.   8 Table of Contents   Soda Ash Segment   We own a 49% non-controlling equity interest in Sisecam Wyoming. Sisecam Resources LP, our operating partner ("Sisecam Resources"), controls and operates Sisecam Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries. Sisecam Resources is a publicly traded master limited partnership that depends on distributions from Sisecam Wyoming in order to make distributions to its public unitholders. 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 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 to the company. We have limited approval rights with respect to Sisecam Wyoming, and our partner controls most business decisions, including decisions with respect to distributions and capital expenditures.   In December 2021, Sisecam Resources, the owner of the remaining 51% of our soda ash business was subject to a change in control. Prior to the transaction, Sisecam Wyoming was referred to as Ciner Wyoming and Sisecam Resources was referred to as Ciner Resources L.P. Upon closing of the transaction, Ciner Enterprises Inc., the indirect owner of approximately 74% of the partnership units of Ciner Resources L.P., sold 60% of its interest in Ciner Resources Corporation, the parent company of Ciner Resources L.P., to Sisecam Chemicals USA Inc. (“Sisecam USA”), an indirect subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş. Ciner Resources Corporation subsequently changed its name to Sisecam Chemical Resources LLC and Ciner Resources L.P. changed its name to Sisecam Resources L.P. Following the transaction, we continue to have the right to appoint three of the seven Board of Managers of Sisecam Wyoming. Sisecam USA has the right to direct the appointment of four members of the Sisecam Wyoming Board of Managers that are allocated to Sisecam Resources.   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 Basin of 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 naturally occurring soft mineral, is also known as sodium sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. Sisecam Wyoming processes trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other consumer and industrial products. The vast majority of the world’s accessible trona is located in the Green River Basin. According to historical production statistics, approximately 30% of global soda ash is produced by processing trona, with the remainder being produced synthetically through chemical processes. The costs associated with procuring the materials needed for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-based production consumes less energy and produces fewer undesirable by-products than synthetic production.   Sisecam Wyoming’s Green River Basin surface operations are situated on approximately 2,360 acres in Wyoming (of which, 880 acres are owned by Sisecam Wyoming), and its mining operations consist of approximately 24,000 acres of leased and licensed subsurface mining area. The facility is accessible by both road and rail. Sisecam Wyoming uses seven large continuous mining machines and 14 underground shuttle cars in its mining operations. Its processing assets consist primarily of 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 carbonate dissolved in water. Sisecam Wyoming then adds activated carbon to filters to remove organic impurities, which can cause color contamination in the final product. The resulting clear liquid is then crystallized in evaporators, producing sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge to remove 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 then stored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. Sisecam Wyoming’s storage silos can hold over 58,900 short tons of processed soda ash at any given time. The facility is in good working condition and has been in service for 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 carbonate decahydrate, 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 the Green 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 refining process. 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 Sisecam Wyoming to reduce waste storage needs and convert what is typically a waste product into a usable raw material. Sisecam Wyoming anticipates that its current deca stockpiles will be exhausted by 2024 and that production rates will decline approximately 200,000 short tons per year if that production capacity is not replaced.   Shipping and Logistics. For the year ended December 31, 2022, Sisecam Wyoming assisted the majority of its domestic customers in arranging their freight services.   All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended December 31, 2022, Sisecam Wyoming shipped over 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 Sisecam Wyoming 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 it will 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 the Union Pacific rail line during a twelve-month period, they must pay Union Pacific a shortfall payment under the terms of its transportation agreement. During 2022, Sisecam Wyoming had no shortfall payments and does not expect to make any such payments in the future. A leased fleet of more than 2,200 hopper cars serve as dedicated modes of shipment to Sisecam Wyoming's domestic and international customers. For exports, soda ash is shipped on unit trains primarily out of Longview, Washington for bulk shipments. Sisecam Wyoming has contracts securing its export capacity in bulk vessels and containers vessels. From these ports, soda ash is loaded onto ships for delivery 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 pay for 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 with vessel owners and carriers securing capacity and reducing market risk fluctuation.    9 Table of Contents   Customers . Sisecam Wyoming generated approximately half of its gross revenue from export sales, which consist of both customers as well as distributors who serve as its channel partners in certain markets. The two largest customers in its portfolio are distributors in its export network who, on a combined basis, make up 26% of its total gross revenue.   For customers in North America, Sisecam Chemical Resources LLC ("Sisecam Chemical Resources") typically enters into contracts on Sisecam Wyoming’s behalf with terms ranging from one to three years. Sisecam Chemical Resources is the parent company of the sole member of the general partner of our operating partner, Sisecam Resources. Sisecam Chemical Resources is owned 60% by Sisecam USA and 40% by Ciner Enterprises Inc. Under these contracts, customers generally agree to purchase either minimum estimated volumes of soda ash or a certain 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 with its customers, substantially all sales are made pursuant to written agreements and not through spot sales. In 2022, Sisecam Wyoming had more than 80 domestic customers and has had long-term relationships with the majority of its customers.   Sisecam Wyoming’s customers consist primarily of glass manufacturing companies, which account for 50% or more of the consumption of soda ash around the world, and chemical and detergent manufacturing companies.   Sisecam Chemicals has now completed two full years directly managing its international sales, marketing and logistics activities since exiting ANSAC at the end of 2020. Sisecam Chemicals took direct control of these activities to improve access to customers and gain control over placement of its sales in the international marketplace. This enhanced view of the global market allows Sisecam chemicals to better understand supply/demand fundamentals thus allowing better decision making for its business. Sisecam Chemicals continues to optimize its distribution network leveraging strengths of existing distribution partners while expanding as its business requires 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 at Sisecam Wyoming’s option upon expiration. Sisecam Wyoming pays royalties to the State of Wyoming, the U.S. Bureau of Land Management and Sweetwater Royalties LLC, 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 Occidental Petroleum Corporation (formerly an affiliate of Anadarko Petroleum Corporation). The royalties are calculated based upon a percentage of the value of soda ash and related 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 River Basin facility. Sisecam Wyoming is also obligated to pay annual rentals to its lessors and licensor regardless of actual sales. In addition, Sisecam Wyoming pays a production 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 mined and 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 continuous mining operations and intends to continue renewing the leases and license as has been historical practice.   Expansion Project. Sisecam Wyoming announced a significant capacity expansion capital project in 2019 that could increase production levels to up to 3.5 million tons of soda ash per year. Basic design work and cost analysis were completed and necessary permits were obtained. However, in light of significant cost inflation, Sisecam Wyoming has decided not to proceed with the project at this time. Sisecam Wyoming continues to remain focused on evaluating capacity expansion opportunities.   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 ash production plant. Our partner, Sisecam Resources, manages the mining and plant operations. We appoint three of the seven members of the Board of Managers of Sisecam Wyoming and have certain limited negative controls relating to the company.   Significant Customers   We have a significant concentration of revenues from Alpha, with total revenues of $102.4  million in 2022 from several different mining operations, including wheelage revenues. We also have a significant concentration of revenues with Foresight and its subsidiaries, with total revenues of $65.6  million i n 2022 from all of their mining operations, including transportation and processing services revenues, coal overriding royalty revenues and wheelage revenues. 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 producing properties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers in various 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, coal quality, 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 also affected by demand for electricity and steel, as well as government regulations, technological developments and the availability and the cost of generating power from alternative 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 competitors are 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-term deterioration in the soda ash market. Other competitors, even if smaller in size, may have greater experience and stronger relationships in their local markets. Competitive pressures could make it more difficult for Sisecam Wyoming to retain its existing customers and attract new customers, and could also intensify the negative impact of factors 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 or regulatory actions that directly or indirectly increase the cost or limit the use of soda ash.   10 Table of Contents   Title to Property   We owned substantially all of our coal and aggregates mineral rights in fee as of December 31, 2022. We lease the remainder from unaffiliated third parties. Sisecam Wyoming 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 confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the 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. State law and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the existence of the severed estates will materially impede development of the minerals on our properties.   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 include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration 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, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls ("PCBs"). Because of extensive, comprehensive and often ambiguous regulatory requirements, violations during natural resource extraction operations 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 expected to continue to be significant. Our lessees in our coal and aggregates royalty businesses are required to post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closures, including the cost of treating mine water discharge when necessary. In many states our lessees also pay taxes into reclamation funds that states use to achieve reclamation where site specific performance bonds are inadequate to do so. Determinations by federal 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 of operations if adequate levels of bonding cannot be maintained. We do not accrue for reclamation costs because our lessees are both contractually liable and liable under the permits they hold for all costs relating to their mining operations, including the costs of reclamation and mine closures. Although the lessees typically accrue adequate 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 impact of its power generation activities, which has affected and is expected to continue to affect demand for coal mined from our properties. Current and future proposed legislation 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 coal and 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 a separate 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’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-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 additional emissions 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 Federal Implementation Plans on over 20 states to implement the 2015 National Ambient Air Quality Standards (NAAQS) for ozone. Installation of additional emissions control technologies and other measures required under EPA regulations make 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 and operation 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 negatively impacted 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 with existing or proposed rules and regulations would have a material adverse effect on our coal-related revenues.   11 Table 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 because emissions of such gases are, according to EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on its findings, EPA began adopting 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, including coal-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 and renewables 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 alternatively result 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 being challenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit. In February 2016, the Supreme 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, EPA issued a proposed rule repealing the CPP Rule and issued an Advance Notice of Proposed Rulemaking soliciting information regarding a potential replacement rule to the CPP Rule. In August 2018, EPA formally proposed the Affordable Clean Energy ("ACE") Rule, which would replace the CPP Rule. The ACE Rule contemplates a narrower approach than the CPP Rule, focusing on efficiency improvements at existing power plants and eliminating the CPP Rule’s broader goals that envisioned switches 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 its authority 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 Rule went 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 CPP Rule as moot. The ACE Rule was challenged by public health groups, environmental groups, states, municipalities, industry groups, and power providers. The legal challenges 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 based on 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 only consider 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 a written 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 “Major Questions 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 generating units. The final rule requires new steam generating units to use highly efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture and storage technology. The final emission standard is less stringent than EPA had originally proposed due to updated cost assumptions, but could still have a material adverse 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 of Appeals 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 EPA reviews the rule. In December 2018, EPA issued a proposed rule revising the best system of emission reduction (“BSER”) for newly constructed coal-fired electric generating 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 in abeyance 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 to vacate and remand the “significant contribution” final rule. On April 5, 2021, the D.C. Circuit vacated and remanded the January 2021 final rule.   President Obama also announced an emission reduction agreement with China’s President Xi Jinping in November 2014. The United States pledged that by 2025 it would 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, at which 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 is no way to estimate the impact of these climate pledges and agreements, they could ultimately have an adverse effect on the demand for coal, both nationally and internationally, if implemented. In 2019, President Trump withdrew from the Paris Climate Agreement. On February 19, 2021, the United States officially rejoined the Paris Climate Agreement per President Biden’s order signed January 20.   Hazardous Materials and Waste   The Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or the Superfund law) and analogous state laws impose liability, 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 release of a “hazardous substance” into the environment. We could become liable under federal and state Superfund and waste management statutes if our lessees are unable to pay environmental cleanup costs relating to hazardous substances. In addition, we may have liability for environmental clean-up costs in connection with Sisecam Wyoming's soda ash businesses.   12 Table of Contents   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 create two permitting programs for mining operations. The National Pollutant Discharge Elimination System (NPDES) program under Section 402 of the statute is administered 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 is administered by the Army Corps of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise “waters of the 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 commonly understood to be a stream or wetlands. The Clean Water Act and its regulations prohibit the unpermitted discharge of pollutants into such waters, including those from a 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 number of 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 implement the 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 revising the 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 to the 2015 WOTUS rule, the petitioners filed amended complaints to include allegations challenging the 2020 rule. In addition, various industry groups, environmental groups, and states filed new legal challenges to the 2020 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the 2020 rule. In light of this order, agencies have reverted to interpreting WOTUS in line with the pre-2015 regulatory regime. In late November 2021, EPA proposed a rule to revise the definition yet again, this time to restore the pre-2015 definition, with updates to reflect recent Supreme Court decisions.   In connection with 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 be unachievable 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, several citizen 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, whereas others alleged that discharges of conductivity and sulfate were causing violations of West Virginia’s narrative water quality standards, which generally prohibit adverse effects 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 quality standard 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 the United States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in large treatment expenses for our lessees. In 2015, the West Virginia Legislature enacted certain changes to West Virginia’s NPDES program to expressly 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, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.   13 Table 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 since the 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. The Mine 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, imposes comprehensive health and safety standards on all mining operations. In addition, the Black Lung Acts require payments of benefits by all businesses conducting current 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 scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. Since 2006, heightened scrutiny has been applied to the safe 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 been assessed for non-compliance. Operating companies and their supervisory employees have also been subject to criminal convictions. The Mine Safety and Health Administration ("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 injuries or 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 the responsibility of reclaiming the land and compensating the landowner for types of damages occurring as a result of mining operations. To ensure compliance with any reclamation obligations, mine operators are required to post performance bonds. Our coal lessees are contractually obligated under the terms of our leases to comply with all federal, state and local laws, including SMCRA. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the reclamation plan approved by the state regulatory authority. In addition, higher and better uses of the reclaimed property 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 with obtaining 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 that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay 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 for reclaiming 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 currently planned 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 the following 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 exercised by 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 to create significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coal operators.   Employees and Labor Relations   As of December 31, 2022, affiliates of our general partner employed 54 people who directly supported our operations. None of these employees were subject to a collective bargaining agreement.   Website Access to Partnership Reports   Our Internet address is www.nrplp.com. We make available free of charge on or through our Internet website our Annual Report on Form 10-K, Quarterly Reports on Form 10-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 soon as 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 part of this report. In addition, the SEC maintains an Internet site 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 our Board of Directors, 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 and Ethics, our Disclosure Controls and Procedures Policy, our Corporate Governance Guidelines and our committee charters will be made available upon written request to our principal executive office at 1415 Louisiana St., Suite 3325, Houston, Texas 77002.   14 Table 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 and our 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 actual amount 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 general partner. Cash distributions are dependent primarily on cash flow, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits. The actual amount of cash we have to distribute each quarter is reduced by payments in respect of debt service and other contractual obligations, including distributions on the preferred units, fixed charges, maintenance capital expenditures, and reserves for future operating or capital needs that the board of directors may determine are appropriate. We have significant debt service obligations and obligations to pay cash distributions on our preferred units. To the extent our board of directors deems appropriate, it may determine to decrease the amount of the quarterly distribution on our common units or suspend or eliminate the distribution on our common units altogether. In addition, because our unitholders are 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 we make. 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 Our Unitholders—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 of our 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 amount in 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 Financial Condition 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, 2022, we and our subsidiaries had approximately $169.1 million of total indebtedness. The terms and conditions governing the indenture for Opco’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 our operations 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 or acquisitions 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 governing their 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, regulatory and 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 cash flow 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 unattractive prices, including higher interest rates. We are required to make substantial principal repayments each year in connection with Opco’s senior notes, with approximately $40 million due thereunder during 2023. To the extent we borrow to make some of these payments, we may not be able to refinance these amounts on terms acceptable to us, 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. Our ability 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 future events 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 of default could adversely affect our business, financial condition and results of operations.   15 Table of Contents   The ongoing COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and ability to make cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.   The COVID-19 pandemic adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities and global trading markets. Coal markets faced substantial challenges prior to the pandemic, and widespread increases in unemployment and decreases in electricity and steel 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. Our board 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 to uncertainties created by the pandemic. In addition, Sisecam Wyoming suspended cash distributions to its members in 2020 due to adverse effects of the pandemic on the global and domestic soda ash markets. Both companies have resumed distributions, however there remains a risk that distributions could be suspended in the future due to a resumption of pandemic uncertainties.   As economic activity began to recover throughout 2021 and 2022, so did supply and demand for coal and soda ash. While the outbreak appeared to be trending downward, particularly as vaccination rates increased, new variants of COVID-19 emerged, including the highly transmissible Delta and Omicron variants, spreading throughout the United States and globally and causing significant uncertainty. The full extent to which the COVID-19 pandemic will impact our results is not fully known and is evolving, and will depend on future developments, which are highly uncertain and cannot be predicted. These include the severity, duration and spread of COVID-19, the success of actions taken by governments and health organizations to combat the disease and treat its effects, including additional remedial legislation, the emergence of any new COVID-19 variants that may arise, the timing, availability, effectiveness and adoption rates of vaccines and treatments and the extent to which, and when, general economic and operating conditions recover. Accordingly, any resulting financial impact cannot be reasonably estimated at this time but such amounts may be material. To the extent our board of directors deems necessary, it may determine to suspend cash distributions in future quarters as a result of the 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 adverse effect 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 prices decline 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 ongoing 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 power generation. The abundance and ready availability of cheap natural gas, together with increased governmental regulations on the power generation industry has caused a 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 coal prices, 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 increased competition 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 is produced is tied to global economic conditions, declines in those conditions could result in the decline of steel, coke and metallurgical coal production. Since metallurgical 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 as metallurgical 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 future lessee bankruptcy filings could create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our business and 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. A long-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 December 31, 2022, we recorded impairment charges of approximately $4.5 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.   16 Table 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 to make 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 are likely to remain volatile in the future. The prices Sisecam Wyoming receives for its soda ash depend on numerous factors beyond Sisecam Wyoming’s control, including the COVID-19 pandemic, worldwide and regional economic and political conditions impacting supply and demand. In addition, the impact of the Sisecam Chemical Resources' exit from ANSAC and Sisecam Wyoming’s transition to the utilization of Sisecam Group’s global distribution network for some of its export operations beginning 2021 could affect prices received for export sales. Glass manufacturers and other industrial customers drive most of the demand for soda ash, and these customers experience significant fluctuations in demand and production costs. Competition from increased use of glass substitutes, such as plastic and recycled glass, has had a negative effect on demand 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 make distributions 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, which accounted for approximately 26% of our total revenues in 2022. We also own significant interests in all of Foresight’s mining operations, which accounted for approximately 17% of our total revenues in 2022. Certain other lessees have made acquisitions over the past few years resulting in their having an increased interest in our 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 of operations.   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 of operations.   While current coal prices have recovered substantially, the recent coal price environment, together with high operating costs and limited access to capital, has caused 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 extent our 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 the financial 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, operations on 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 of operations.   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 production from 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’ control including: • 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 are experiencing rising costs related to regulatory compliance, insurance coverage, permitting and reclamation bonding, transportation, and labor. Increased costs result in decreased 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 liabilities resulting 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 could have a material adverse effect on our business and results of operations.   17 Table of Contents   The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changes in 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 actions to 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 plant closures. Further, regulations regarding new coal-fueled power plants could adversely impact the global demand for coal. The potential financial impact on us of existing and 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 on coal 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 and availability of competing fuels for power plants and environmental and other governmental regulations. We expect that substantially all newly constructed power plants in 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 cleaner burning fuel. The increasingly stringent requirements of rules and regulations promulgated under the federal Clean Air Act have resulted in more electric power generators 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 reduced coal 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 generating facilities, including the Cross-State Air Pollution Rule (CSAPR) as revised in 2021, regulating emissions of nitrogen oxide and sulfur dioxide, and the Mercury and Air Toxics Rule (MATS), regulating emissions of hazardous air pollutants. Installation of additional emissions control technologies and other measures required under these 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 plant closures. 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 material adverse 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 and Properties—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 and investment 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, especially fossil fuel combustion, on global climate issues. In addition to government regulation of greenhouse gas and other air pollutant emissions, there have also been efforts in 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. One example 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 their investment portfolios with net zero emissions by 2050. The impact of such efforts may adversely affect our ability to raise capital. In addition, a number of insurance companies have taken action 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 insurance coverage 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 matters and disclosures, may result in increased costs, reduced profits, increased investigations and litigation, and negative impacts on our access to capital.   Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their 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 investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative 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 price and 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 to invest 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 that may 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 local environmental, health and safety laws, including mine safety regulations and governmental enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or 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 new or 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, our coal lessees have substantial reclamation obligations on properties where mining operations have been completed and are required to post performance bonds for their reclamation obligations. To the extent an operator is unable to satisfy its reclamation obligations or the performance bonds posted are not sufficient to cover those obligations, regulatory authorities or citizens groups could attempt to shift reclamation liability onto the ultimate landowner, which if successful, could have a material adverse 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 that allege violations of water quality standards resulting from ongoing discharges of pollutants from reclaimed mining operations, including selenium and conductivity. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations and could result in substantial compliance costs or fines.   18 Table 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 operations within 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, repossess the 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 to find 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 existing lessee 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 we enter 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, it may 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 and capital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture and through 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 controls most business decisions, including decisions with respect to distributions and capital expenditures. During 2020, Sisecam Wyoming suspended cash distributions to its members 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 that additional suspensions will not occur in the future. In December 2021, the parent of the 51% owner of Sisecam Wyoming (formerly Ciner Wyoming) sold 60% of its interest to Sisecam Chemicals USA 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 of Managers of Sisecam Wyoming, Sisecam USA will appoint three and Ciner Enterprises Inc. will appoint one. Any changes to the distribution policy or the capital expenditure plans approved by the newly constituted Board of Managers could adversely affect the future cash flows to NRP and the financial condition and results of operations of Sisecam Wyoming.   In addition, we are ultimately responsible for operating the transportation infrastructure at Foresight’s Williamson mine, and have assumed the capital and operating risks associated with that business. As a result of these investments, we could experience increased costs as well as increased liability exposure associated with operating these facilities.   Sisecam Wyoming ’ s deca stockpiles will substantially deplete by 2024 and its production rates will decline approximately 200,000 short tons per year if Sisecam Wyoming does not make further investments or 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 approximately 200,000 short tons (approximately 7% of Sisecam Wyoming production), which would impact Sisecam Wyoming's profitability. While Sisecam Wyoming is currently evaluating whether and when to pursue one or more initiatives that could offset this decline as well as provide additional soda ash production above current rates, there is no guarantee that any such initiatives or investments will be executed successfully, in a timely manner, or if at all to enable Sisecam Wyoming to maintain its current rates of production.   19 Table 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 our properties.   Transportation costs represent a significant portion of the total delivered cost for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make minerals produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from producers in other parts of the country.   Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and/or other events could temporarily impair the ability of our lessees to supply coal to their customers and/or increase their costs. Many of our lessees are currently experiencing transportation-related issues due in particular to decreased availability and reliability of rail services and port congestion. Our lessees’ transportation providers may face difficulties in the future that would impair the ability of our lessees to supply 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 in rail freight, trucking and ocean vessel rates. Increases in transportation costs, including increases resulting from emission control requirements, port taxes and fluctuations 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 could make Sisecam Wyoming’s soda ash less competitive than soda ash produced by competitors that have other means of transportation or are located closer to their customers. 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 by supply 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, and alternative methods of transportation are impracticable or cost prohibitive. For the year ended December 31, 2022, Sisecam Wyoming shipped over 90% of its soda ash from 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 transportation of 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 of operations.   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 of minimum royalty payments.   Mineral supply contracts generally do not require operators to satisfy their obligations to their customers with resources mined from specific locations. Several factors may influence a lessee’s decision to supply its customers with minerals mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. In addition, lessees move on and off of 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 properties we 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 be identified in a subsequent period.   We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.   Risks Related to Our Structure   Unitholders may not be able to remove our general partner even if they wish to do so.   Our general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis.   Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general 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 vote along with the common unitholders on an as-converted basis). Because of their substantial ownership in us, the removal of our general partner would be difficult without 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 otherwise change 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 or its 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 other limitations 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 the trading price.   20 Table 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 distributions on 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 based on 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 common unitholders. 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 remove our 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 Stock Exchange ("NYSE") rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units (including additional preferred units) without common unitholder approval (subject to applicable NYSE rules). In addition, we may issue additional common units upon the exercise of the outstanding warrants held by Blackstone and GoldenTree. 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 it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.   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, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner.   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 partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability; • under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of 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 to one of its affiliates or to us.   In addition, Blackstone has certain consent rights and board appointment and observation rights. GoldenTree also has more limited consent rights. In the exercise of their applicable consent rights and/or board rights, conflicts of interest could arise between us and our general partner on the one hand, and Blackstone or GoldenTree on the other hand.   21 Table 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 our debt instruments and the triggering of payment obligations under compensation arrangements.   Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors and officers with its own choices and to control their decisions and actions.   In addition, a change of control would constitute an event of default under our debt agreements. During the continuance of an event of default under our debt agreements, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us and/or declare all amounts payable by us immediately 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 at the liquidation preference or convert all of their preferred units into common units. A change of control also may trigger payment obligations under various compensation 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 obligations that are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.   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-level taxation 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 become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.   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 tax purposes. 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 purposes unless we satisfy a "qualifying income" requirement. Based on our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. 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 qualifying income 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 as an 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 and would 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 distribution to 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 and other 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 expand our 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 the cash 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 or differing 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 the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment.   In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can 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 a manner 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 or impossible 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 to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our units.   22 Table 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 future legislation.   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 preferences relating 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) repealing the percentage depletion allowance with respect to coal properties. If enacted, these changes would limit or eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of 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 of our 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 unitholders are 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 cash distributions 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 them with 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) and passive 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 will not 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 passive activities 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 of properties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions made with 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 corresponding cash 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 gain resulting from the sale without receiving a cash distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as ordinary taxable income. Our unitholders may be allocated income and gain from these transactions, and income tax liabilities arising therefrom may exceed 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, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to the unitholder’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 our cash 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 the positions 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 units and 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 costs will reduce our cash available for distribution.   If   the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, 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.   Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, 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 under these rules, our general partner may elect to either pay the taxes (including any applicable penalties and 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 and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustments into account and pay any resulting taxes (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 will be 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 audit adjustment, 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 make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.   23 Table 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 those common 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's common 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 our common 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 original cost. 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 tax liability 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 to potential recapture items, including depletion and depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if 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 of individuals, 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 our allocations 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 sale of 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 limitation under 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 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.   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 be unrelated 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 other disposition 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 our units.   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 or business. 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 or business. 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 sells or 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 withholding tax 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 any distribution 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 and lack 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 to such 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 highest applicable 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 decrease of 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 traded partnership, 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 publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should 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 challenge this 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 that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available 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 on the value of our common units or result in audit adjustments to our unitholders' tax returns.   24 Table of Contents   We have adopted certain valuation methodologies in determining a unitholder ’ s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies 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 fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates 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 these valuation 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 our unitholders. 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 in audit 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 ownership 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 this treatment, which could 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 the ownership 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, we generally 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 discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our 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 of those 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 may recognize 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 subject of 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 with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from 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 their brokers 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 or own 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 unitholders do 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 of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in a number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is 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 technologies and services. Threats to information technology systems associated with cybersecurity 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 sensitive information or render data or systems unusable.   While we presently maintain insurance coverage to protect against cybersecurity risks, we cannot ensure that it will be sufficient to cover any particular losses we may experience as a result of such cyber-attacks. Any cyber incident could have a material adverse effect on our business, financial condition and results of operations.   25 Table of Contents   ITEM 1B. UNRESOLVED STAFF COMMENTS   None.   ITEM 3. LEGAL PROCEEDINGS   We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, 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.   26 Table 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 16, 2023 , there were approximately 11 ,000 b eneficial and registered holders 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 presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consists 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 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 its subsidiaries. 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").   27 Table of Contents   Non-GAAP Financial Measures   Distributable Cash Flow   Distributable cash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings, proceeds from asset sales and disposals, including sales of discontinued operations, and return of long-term contract receivables, less maintenance capital expenditures. DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies. In addition, DCF presented below is not calculated 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 able to increase quarterly distributions to our common unitholders. DCF 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.   Free Cash Flow   Free cash flow ("FCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables, less maintenance and expansion capital expenditures and cash flow used in acquisition costs classified as investing or financing activities. FCF is calculated before mandatory debt repayments. FCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. FCF may not be calculated the same for us as for other companies. 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.   Cash Flow Cushion   Cash flow cushion represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables; less maintenance and expansion capital expenditures, cash flow used in acquisition costs classified as investing or financing activities, one-time beneficial items, mandatory Opco debt repayments, preferred unit distributions and redemption of PIK units, common unit distributions and warrant cash settlements. Cash flow cushion is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Cash flow cushion is a supplemental liquidity measure used by our management to assess our ability to make or raise cash distributions to our common and preferred unitholders and our general partner and repay debt or redeem preferred units.   Adjusted EBITDA   Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) less equity earnings from unconsolidated investment, net income attributable to non-controlling interest and gain on reserve swap; plus total distributions from unconsolidated investment, interest expense, net, debt modification expense, 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 of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies. In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnership agreement or Consolidated EBITDDA as defined in Opco's debt agreements. See " Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net " included elsewhere 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 our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.   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 defined above. 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 to generate 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 other companies and is not a substitute for, and should not be used in conjunction with, GAAP financial ratios.    28 Table 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 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 and soda ash production business. Our common units trade on the New York Stock Exchange under the symbol "NRP." 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, as well as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energy economy 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 Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries.   Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest and financing, 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, 2022 are as follows:       Operating Segments     Corporate and           (In thousands)   Mineral Rights     Soda Ash     Financing     Total   Revenues and other income   $ 329,167     $ 59,795     $ —     $ 388,962   Net income (loss)   $ 267,448     $ 59,635     $ (58,591 )   $ 268,492   Asset impairments     4,457       —       —       4,457   Net income (loss) excluding asset impairments   $ 271,905     $ 59,635     $ (58,591 )   $ 272,949   Adjusted EBITDA (1)   $ 294,424     $ 44,675     $ (21,852 )   $ 317,247                                     Cash flow provided by (used in) continuing operations                                 Operating activities   $ 262,807     $ 44,672     $ (40,641 )   $ 266,838   Investing activities   $ 2,806     $ —     $ (118 )   $ 2,688   Financing activities   $ (614 )   $ —     $ (365,341 )   $ (365,955 ) Distributable cash flow (1)   $ 265,613     $ 44,672     $ (40,759 )   $ 269,526   Free cash flow (1)   $ 264,530     $ 44,672     $ (40,759 )   $ 268,443   Cash flow cushion (1)     N/A       N/A       N/A     $ 145,084     (1) See"—Results of Operations" below for reconciliations to the most comparable GAAP financial measures.   29 Table of Contents   Current Results/Market Commentary   Business Outlook and Quarterly Distributions   We generated $266.8 million of operating cash flow and $268.4 million of free cash flow during the year ended December 31, 2022, and ended the year w ith $99.1 million of l iquidity consisting of $39.1  million of cash and cash equivalents and $60 million of borrowing capacity under our Opco Credit Facility. During the year, we refinanced, upsized, and extended our Opco Credit Facility to $130 million due 2027. Also during the year, we permanently retired all $300 million of our 2025 Senior Notes. As of December 31, 2022 our leverage ratio was 0.5x.   In February 2023, the Board of Directors declared a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2022 as well as a $7.5 million cash distribution on the preferred units with respect to the fourth quarter of 2022. Additionally, NRP has announced it will pay a one-time, special cash distribution of $2.43 in March 2023 to help cover unitholder tax liabilities for 2022. Future distributions on our common and preferred units will 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 the Board determines is necessary for future operating and capital needs.    In February 2023, we received a notice from holders of our Class A Preferred Units exercising their right to either convert or redeem, at the election of NRP, an aggregate of 47,499 Class A Preferred Units. We chose to redeem the preferred units for $47.5 million in cash plus any accrued and unpaid distributions, utilizing cash on hand and borrowings under our revolving credit facility. Of the originally issued 250,000 Class A Preferred Units, 202,501 Class A Preferred Units remain outstanding as of the date of this report.    Mineral Rights Business Segment   Metallurgical coal prices reached historical highs and were the primary driver of strong segment performance. Numerous factors continue to provide support for met pricing. Supply chain disruptions, labor shortages and years of underinvestment in new coal production capacity continue to undermine producers’ ability to bring new production online to meet demand. While met prices have pulled back from the peaks reached last year, we continue to believe met prices will remain well-supported for the foreseeable future.    Thermal coal prices also reached record highs in 2022, but have declined significantly in recent months due to unusually warm weather in Europe and North America as well as lower natural gas prices. While we do not expect to see thermal prices rebound to last year’s levels, many of the factors that provided support to prices over the last year still exist. Boycotts of Russian coal continue to force European buyers to source coal from other regions, including the U.S. Operators will continue to be burdened by labor shortages, pressure from governments, regulators, activists, and capital providers, which will limit ability to increase thermal production to meet demand. China appears to be relaxing its three-year ban on Australian coal imports with the recent approvals for several Chinese companies to buy Australian coal. Additional demand from a Chinese economy emerging from a zero-COVID policy should provide additional support for prices. We expect these factors to keep thermal prices elevated relative to historical levels for the foreseeable future   We continue to explore and identify carbon neutral revenue sources across our large portfolio of land and mineral assets. The types of opportunities include the sequestration of carbon dioxide underground and in standing forests, and the generation of green electricity using geothermal, solar, and wind energy. We own the rights to sequester carbon dioxide ("CO 2 ") on approximately 3.5 million acres of pore space in the southern United States. As announced previously, in the first quarter of 2022 we executed our first subsurface CO 2  sequestration lease on 75,000 acres of underground pore space we own in southwest Alabama with the potential to store over 300 million metric tons of CO 2 . In October of 2022, we announced our second subsurface CO 2  transaction with the execution of a lease for approximately 65,000 acres of pore space we control near southeast Texas with estimated storage capacity of at least 500 million metric tons of CO 2 . In total, we have approximately 140,000 acres of pore space under lease for carbon sequestration with estimated CO 2  storage capacity of 800 million metric tons. While the timing and likelihood of additional cash flows being realized from these activities is uncertain, we believe our large ownership footprint throughout 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, 2022 were higher by $37.9  million compared to the prior year period primarily as a result of increased international sales prices. Cash provided by operating activities and free cash flow during the year ended December 31, 2022 increased $33.6 million as compared to the prior year period due to Sisecam Wyoming reinstating its regular quarterly cash distributions beginning in the fourth quarter of 2021.   Strong international sales at Sisecam Wyoming for the year ended December 31, 2022, more than offset input cost inflation, supply chain difficulties, and softening demand in the second half of the year due to China's Zero-Covid policy and concerns of slowing economic growth.    30 Table of Contents   Results of Operations   Year Ended December 31, 2022 and 2021 Compared   Revenues and Other Income   The following table includes our revenues and other income by operating segment:       For the Year Ended December 31,             Percentage   Operating Segment (In thousands)   2022     2021     Increase     Change   Mineral Rights   $ 329,167     $ 194,493     $ 134,674       69 % Soda Ash     59,795       21,871       37,924       173 % Total   $ 388,962     $ 216,364     $ 172,598       80 %   31 Table 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 categories of other revenues and other income:       For the Year Ended December 31,     Increase     Percentage   (In thousands, except per ton data)   2022     2021     (Decrease)     Change   Coal sales volumes (tons)                                 Appalachia                                 Northern     1,696       1,335       361       27 % Central     13,646       12,279       1,367       11 % Southern     1,784       1,571       213       14 % Total Appalachia     17,126       15,185       1,941       13 % Illinois Basin     11,135       9,388       1,747       19 % Northern Powder River Basin     4,288       3,151       1,137       36 % Gulf Coast     385       55       330       600 % Total coal sales volumes     32,934       27,779       5,155       19 %                                   Coal royalty revenue per ton                                 Appalachia                                 Northern   $ 8.75     $ 6.51     $ 2.24       34 % Central     10.47       5.71       4.76       83 % Southern     13.50       9.14       4.36       48 % Illinois Basin     2.50       2.12       0.38       18 % Northern Powder River Basin     4.07       3.54       0.53       15 % Gulf Coast     0.58       0.60       (0.02 )     (3 )% Combined average coal royalty revenue per ton     6.90       4.47       2.43       54 %                                   Coal royalty revenues                                 Appalachia                                 Northern   $ 14,836     $ 8,691     $ 6,145       71 % Central     142,930       70,149       72,781       104 % Southern     24,076       14,355       9,721       68 % Total Appalachia     181,842       93,195       88,647       95 % Illinois Basin     27,856       19,917       7,939       40 % Northern Powder River Basin     17,437       11,151       6,286       56 % Gulf Coast     223       33       190       576 % Unadjusted coal royalty revenues     227,358       124,296       103,062       83 % Coal royalty adjustment for minimum leases     (402 )     (20,207 )     19,805       98 % Total coal royalty revenues   $ 226,956     $ 104,089     $ 122,867       118 %                                   Other revenues                                 Production lease minimum revenues   $ 5,854     $ 14,269     $ (8,415 )     (59 )% Minimum lease straight-line revenues     18,792       20,564       (1,772 )     (9 )% Carbon neutral initiative revenues     8,600       13,790       (5,190 )     (38 )% Wheelage revenues     13,961       10,065       3,896       39 % Property tax revenues     5,878       6,028       (150 )     (2 )% Coal overriding royalty revenues     3,434       4,367       (933 )     (21 )% Lease amendment revenues     3,201       4,696       (1,495 )     (32 )% Aggregates royalty revenues     3,299       1,889       1,410       75 % Oil and gas royalty revenues     16,161       4,506       11,655       259 % Other revenues     877       933       (56 )     (6 )% Total other revenues   $ 80,057     $ 81,107     $ (1,050 )     (1 )% Royalty and other mineral rights   $ 307,013     $ 185,196     $ 121,817       66 % Transportation and processing services revenues     21,072       9,052       12,020       133 % Gain on asset sales and disposals     1,082       245       837       342 % Total Mineral Rights segment revenues and other income   $ 329,167     $ 194,493     $ 134,674       69 %   32 Table of Contents   Coal Royalty Revenues   Approximately 70% of coal royalty revenues and approximately 45% of coal royalty sales volumes were derived from metallurgical coal during the year ended December 31, 2022. Total coal royalty revenues increased $122.9  million from 2021 to 2022. Strong coal prices in 2022 were primarily driven by improved demand combined with a limited ability for operators to increase production due to ongoing labor shortages, global supply chain interruptions, and limited access to capital. The discussion by region is as follows:     • Appalachia : Coal royalty revenues increased $88.6 million primarily due to increased coal sales prices and volumes during the year ended December 31, 2022, as compared to the prior year. • Illinois Basin : Coal royalty revenues increased $7.9 million primarily due to higher sales volumes and increased sales prices during the year ended December 31, 2022 as compared during the prior year. Revenues recognized from Foresight in 2021 were fixed as a result of the lease amendment the Partnership entered into with Foresight in 2020 pursuant to which Foresight agreed to pay NRP fixed cash payments in 2020 and 2021 to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreements between the Partnership and Foresight. Revenues from Foresight in 2022 represent traditional royalty and minimum payments. • Northern Powder River Basin : Coal royalty revenues increased $6.3 million primarily due to increased sales volumes as our lessee mined more on our property during 2022 as compared to 2021in accordance with its mine plan.   Other Revenues   Other revenues decreased $1.1 million during the year ended December 31, 2022 as compared to the prior year primarily due to the following: • An  $8.4 million d ecrease in production lease minimum revenues primarily due to the lease amendment with Foresight whereas transportation and processing revenues were based on the recognition of a fixed amount in 2021. • A $5.2  million decreas e in carbon neutral initiative revenues as compared to the prior year. Revenues recognized in 2022 related to carbon neutral transactions that included subsurface CO 2 storage and geothermal while revenues recognized in 2021 related to forest CO 2 sequestration revenues.    These decreases were partially offset by an $11.7  milli on increase in oil and gas royalty revenues primarily due to new wells and increased natural gas prices as compared to the prior year.    Transportation and Processing Services Revenues   Transportation and processing services revenues increased  $12.0  million during the year ended December 31, 2022 as compared to the prior year primarily due to the lease amendment with Foresight whereas transportation and processing revenues were based on the recognition of a fixed amount in 2021. Revenues from Foresight in 2022 represented traditional royalty and minimum payments and were greater than the fixed revenue from 2021.   Soda Ash   Revenues and other income related to our Soda Ash segment increased $37.9  million c ompared to the prior year primarily as a result of increased international sales prices.   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)   2022     2021     (Decrease)     Change   Operating expenses                                 Operating and maintenance expenses   $ 34,903     $ 27,049     $ 7,854       29 % Depreciation, depletion and amortization     22,519       19,075       3,444       18 % General and administrative expenses     21,852       17,360       4,492       26 % Asset impairments     4,457       5,102       (645 )     (13 )% Total operating expenses   $ 83,731     $ 68,586     $ 15,145       22 %                                   Other expenses, net                                 Interest expense, net   $ 26,274     $ 38,876     $ (12,602 )     (32 )% Loss on extinguishment of debt     10,465       —       10,465       100 % Total other expenses, net   $ 36,739     $ 38,876     $ (2,137 )     (5 )%   Total operating expenses increased $15.1 million primarily due to the following:   • A $7.9 million increase in operating and maintenance expenses primarily as a result of higher overriding royalty expense from an agreement with WPPLP in 2022 as compared to 2021. This overriding royalty expense is fully offset by coal royalty revenue we receive from this property. • A $4.5 million increase in general and administrative expenses primarily due to increased incentive compensation expense incurred during 2022 as a result of the Partnership's improved performance as compared to the prior year. • A $3.4 million increase in depreciation, depletion and amortization expense primarily as a result of higher Illinois Basin coal royalty sales volumes during the year ended December 31, 2022, as compared to the prior year.   Total other expenses, net decreas ed $2.1  million pri marily due to a $12.6  million decrease in interest expense, net as a result of less debt outstanding as compared to the prior year, partially offset by a $10.5  million loss on early extinguishment of debt related to the premiums and fees incurrent and write-off of debt issuance costs associated with the retirement of the 2025 Senior Notes during the year ended December 31, 2022.    33 Table 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, 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                                     December 31, 2021                                 Net income (loss)   $ 143,412     $ 21,702     $ (56,212 )   $ 108,902   Less: equity earnings from unconsolidated investment     —       (21,871 )     —       (21,871 ) Add: total distributions from unconsolidated investment     —       11,270       —       11,270   Add: interest expense, net     24       —       38,852       38,876   Add: depreciation, depletion and amortization     19,075       —       —       19,075   Add: asset impairments     5,102       —       —       5,102   Adjusted EBITDA   $ 167,613     $ 11,101     $ (17,360 )   $ 161,354     Net income increased $159.6 million primarily due to the increases in revenues and other income, partially offset by increased operating expenses, both as discussed above. Adjusted EBITDA increased $155.9 million primarily due to a $126.8 million increase in Adjusted EBITDA within our Mineral Rights segment as a result of higher revenues and other income during the year ended December 31, 2022 as discussed above and a $33.6 million increase in Adjusted EBITDA within our Soda Ash segment as a result of higher cash distributions received from Sisecam Wyoming during the year ended December 31, 2022 as compared to the prior year due to Sisecam Wyoming reinstating its regular quarterly cash distributions beginning in the fourth quarter of 2021.   Distributable Cash Flow ("DCF"), Free Cash Flow ("FCF") and Cash Flow Cushion (Non-GAAP Financial Measures)   The following table presents the three major categories of the statement of cash flows by business segment:     Operating Segments                   For the Year Ended (In thousands)   Mineral Rights     Soda Ash     Corporate and Financing     Total   December 31, 2022                                 Cash flow provided by (used in) continuing operations                                 Operating activities   $ 262,807     $ 44,672     $ (40,641 )   $ 266,838   Investing activities     2,806       —       (118 )     2,688   Financing activities     (614 )     —       (365,341 )     (365,955 )                                   December 31, 2021                                 Cash flow provided by (used in) continuing operations                                 Operating activities   $ 159,845     $ 11,106     $ (49,147 )   $ 121,804   Investing activities     2,412       —       —       2,412   Financing activities     (1,132 )     —       (87,354 )     (88,486 )   34 Table of Contents   The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCF, FCF and cash flow cushion:     Operating Segments                   For the Year Ended (In thousands)   Mineral Rights     Soda Ash     Corporate and Financing     Total   December 31, 2022                                 Net cash provided by (used in) operating activities of continuing operations   $ 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   Less: mandatory Opco debt repayments                             (39,396 ) Less: preferred unit distributions and redemption of PIK units                             (49,579 ) Less: common unit distributions                             (34,384 ) Cash flow cushion                           $ 145,084         Operating Segments                   For the Year Ended (In thousands)   Mineral Rights     Soda Ash     Corporate and Financing     Total   December 31, 2021                                 Net cash provided by (used in) operating activities of continuing operations   $ 159,845     $ 11,106     $ (49,147 )   $ 121,804   Add: proceeds from asset sales and disposals     249       —       —       249   Add: return of long-term contract receivable     2,163       —       —       2,163   Distributable cash flow   $ 162,257     $ 11,106     $ (49,147 )   $ 124,216   Less: proceeds from asset sales and disposals     (249 )     —       —       (249 ) Less: acquisition costs     (1,000 )     —       —       (1,000 ) Free cash flow   $ 161,008     $ 11,106     $ (49,147 )   $ 122,967   Less: mandatory Opco debt repayments                             (39,396 ) Less: preferred unit distributions                             (15,571 ) Less: common unit distributions                             (22,645 ) Less: warrant cash settlement                             (9,183 ) Cash flow cushion                           $ 36,172     Cash provided by operating activities, DCF and FCF increased $145.0 million, $145.3 million and $145.5 million, respectively, primarily due to the following:   • Mineral Rights Segment: Cash provided by operating activities, DCF and FCF increased $103.0 million, $103.4 million and $103.5 million, respectively primarily due to the segment's increase in revenues and other income as discussed above.   • Soda Ash Segment: Cash provided by operating activities, DCF and FCF increased $33.6  million as a result of higher cash distributions received from Sisecam Wyoming in 2022 as compared to the prior year as discussed above.   • Corporate and Financing Segment: Cash used by operating activities decreased $8.5 million and DCF and FCF increased $8.4 million primarily due to lower cash paid for interest in 2022 as a result of the repayments of our 2025 Senior Notes during the year.   Cash flow cushion increased $108.9 million as a result of the increase in FCF discussed above and $9.2 million of cash used to settle the exercise of certain of our warrants in 2021, partially offset by:   • $34.0 million of increased cash paid with respect to our preferred units. In 2021 we paid half of our preferred unit distributions in kind and in 2022 we paid all of our preferred unit distributions in cash and redeemed the outstanding paid-in-kind units.   • $11.7  million of increased cash used for common unit distributions as a result of increasing our common unit distributions to $0.75/unit beginning in the second quarter of 2022.    For discussion of our Results of Operations comparing 2021 to 2020, refer to our 2021 Annual Report on Form 10-K filed March 15, 2022 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . "   35 Table of Contents   Liquidity and Capital Resources   Current Liquidity   As of December 31, 2022, we had total liquidity of $99.1 million, consisting of $39.1 million of cash and cash equivalents and $60 million in borrowing capacity under our Opco Credit Facility. We have debt service obligations, including approximately $40 million of principal repayments on Opco’s senior notes in 2023. As discussed previously, during 2022 we permanently retired all of our 9.125% Senior Notes due 2025 and had $70 million drawn on our Opco Credit Facility as of December 31, 2022. We believe our liquidity position provides us with the flexibility to continue paying down debt and manage our business. As of December 31, 2022 our leverage ratio was 0.5x. The following table calculates our leverage ratio:   (In thousands)   For the Year Ended December 31, 2022   Adjusted EBITDA   $ 317,247   Debt—at December 31, 2022   $ 169,087   Leverage Ratio   0.5x     Cash Flows   Year Ended December 31, 2022 and 2021 Compared   Cash flows provided by operating activities increased $145.0 million, from $121.8 million in the year ended December 31, 2021 to $266.8 million in the year ended December 31, 2022 primarily related to increased revenues and other income within our Mineral Rights segment, higher cash distributions received from Sisecam Wyoming, and less cash paid for interest as compared to the prior year, all as discussed above.    Cash flows used in financing activities increased $277.5 million, from $88.5 million in the year ended December 31, 2021 to $366.0 million in the year ended December 31, 2022 primarily due to the following:   • $300.0 million of cash used to retire all of our 2025 Senior Notes in 2022;   • $19.6 million of cash used to redeem the preferred units paid-in-kind during the first quarter of 2022;   • $14.4 million of increased cash used for preferred unit distributions as a result of paying all of our preferred unit distributions in cash in 2022 as compared to a portion in kind in 2021;   • $11.9 million of increased cash used for other items, net, which primarily related to the premiums paid related to the repayment of the 2025 Senior Notes in 2022; and   • $11.7 million of increased cash used for distributions to common unitholders and the general partner as a result of increasing our common unit distributions to $0.75/unit beginning in the second quarter of 2022.   These increases in cash flow used were partially offset by $70 million of borrowings on our Opco Credit Facility in 2022 and $9.2 million of cash used in 2021 to settle the exercise of certain of our warrants.   For discussion of our Cash Flows comparing 2021 to 2020, refer to our 2021 Annual Report on Form 10-K filed March 15, 2022 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. "   36 Table of Contents   Capital Resources and Obligations   Debt, Net   We had the following debt outstanding as of December 31, 2022 and 2021:       December 31,   (In thousands)   2022     2021   Current portion of long-term debt, net   $ 39,076     $ 39,102   Long-term debt, net     129,205       394,443   Total debt, net   $ 168,281     $ 433,545     We have been and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information regarding our 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, 2022:       Payments Due by Period   Debt Obligations (In thousands)   Total     2023     2024     2025     2026     2027     Thereafter   NRP:                                                         Debt principal payments   $ —     $ —     $ —     $ —     $ —     $ —     $ —   Debt interest payments     —       —       —       —       —       —       —   Opco:                                                         Debt principal payments (including current maturities) (1)     169,087       39,396       31,028       14,332       14,331       70,000       —   Debt interest payments (2)     9,794       4,895       2,724       1,450       725       —       —   Total   $ 178,881     $ 44,291     $ 33,752     $ 15,782     $ 15,056     $ 70,000     $ —     (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.   Inflation   Inflation in the United States has been relatively low in previous years, and despite rising costs beginning in 2021 and continuing into 2022, inflation did not have a material impact on operations for the years ended December 31, 2022, 2021 and 2020.   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—Regulation and 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 " Item 13. Certain Relationships and Related Transactions, and Director Independence " in this Annual Report on Form 10-K and is incorporated by reference herein.   37 Table 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 to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See " Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies " in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significant accounting 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 option to 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 sales price 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 five years.   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 the lease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production would exceed consideration expected to 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. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, we recognize breakage revenue from minimums when 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 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 by lessees and the corresponding revenues from those sales. Also included within oil and gas royalty revenues are lease bonus payments, which are generally paid upon the execution of a lease. We also have overriding royalty revenue interests in certain of our coal and aggregates mineral rights. Revenue from these interests is recognized over time based on when the coal is sold.   Carbon neutral initiative revenues. Revenues related to consideration received from carbon neutral initiatives that are recognized at a point in time upon satisfaction of our performance obligation.    Wheelage revenues. Revenues related to fees collected per ton to transport foreign coal across property we own that is recognized over time as transportation across our property occurs.   Other revenues. Other revenues consist primarily of rental payments and surface damage fees related to certain land we own and are recognized straight-line over time as it is earned. Other revenues also include property tax revenues. The majority of property taxes paid on our properties are reimbursable by the lessee and are recognized on a gross basis over time which affects the reimbursement of property taxes by the lessee. Property taxes we pay are included in operating and maintenance expenses on our Consolidated Statements of Comprehensive Income (Loss).   Transportation and processing services revenues. We own transportation and processing infrastructure that is leased to third parties for throughput fees. 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 our contract modifications pertain to our coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices or minimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within royalty and other mineral rights revenues on our Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognized prospectively in accordance with the above lease classification.   38 Table of Contents   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 are recognized when the minimums are contractually owed, production occurs or minimums are 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 revenue relates 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. The long-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-line basis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as royalty revenues from production leases over the next twelve months, we are unable to estimate the current portion of deferred revenue.   Equity in Earnings of Sisecam Wyoming.   We account for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. Our 49% investment in Sisecam Wyoming is accounted for using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortized over its estimated useful life. The carrying value in Sisecam Wyoming is recognized in equity in unconsolidated investment on our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings of Sisecam Wyoming on the Consolidated Statements of Comprehensive Income (Loss). We decrease our investment for our proportional share of distributions received from Sisecam Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are considered returns on investment and classified as operating cash inflows unless the cumulative distributions received exceed our cumulative equity in earnings. The excess of cumulative distributions received over our cumulative equity in earnings are considered returns of investment and classified as investing cash inflows.   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 aggregates mineral 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 estimated economic tonnage as estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of our economic tonnage include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statistical analysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of economic tonnage, including many factors beyond our control. Estimates of economically recoverable tonnage depend upon a number of variable factors and assumptions, any one of which may, if incorrect, 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 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 events such as a reduction in economically recoverable tons or production ceasing on a property for an extended period. A long-lived asset is deemed impaired when the future expected undiscounted 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 usually determined 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 discount rates 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 such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.   Recent Accounting Standards   We do not believe that any other recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our financial statements.   ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   As a smaller reporting company for the year ended December 31, 2022, we are not required to include this disclosure in our 2022 Form 10-K.   39 Table of Contents     ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS       Page Report of Ernst & Young LLP, Independent Registered Public Accounting Firm  (PCAOB ID 42 ) 41 Report of BDO USA, LLP, Independent Registered Public Accounting Firm    (PCAOB ID 243 ) 43 Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm  (PCAOB ID 34 ) 45 Consolidated Balance Sheets as of December   31, 2022 and 2021 46 Consolidated Statements of Comprehensive Income (Loss) for the years ended December   31, 2022, 2021 and 2020 47 Consolidated Statements of Partners ’  Capital for the years ended December 31, 2022, 2021 and 2020 48 Consolidated Statements of Cash Flows for the years ended December   31, 2022, 2021 and 2020 49 Notes to Consolidated Financial Statements 50   40 Table 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, 2022 and 2021, the related consolidated statements of comprehensive income (loss) , partners’ capital, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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 the consolidated financial statements, the Partnership’s investment in Sisecam Wyoming is stated at $306 million and $276 million as of December 31, 2022 and 2021, respectively, and the Partnership’s equity in the net income of Sisecam Wyoming is stated at $60 million in 2022, $22 million in 2021 and $11 million in 2020. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Sisecam Wyoming, 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 control over financial reporting as of December 31, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 2, 2023 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 statements based 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 with the 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 assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of 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 be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, 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 account or disclosure to which it relates.   41 Table of Contents   Impairment Assessment of Mineral Rights   Description of the Matter At December 31, 2022, the Partnership’s mineral rights, net totaled $412 million. As described in Note 2 to the consolidated financial statements, the Partnership evaluates its long-lived assets (inclusive of mineral rights) for possible impairment whenever events or changes in circumstances indicate that the carrying amounts of the asset may not be recoverable (“triggering events”). Management evaluates various qualitative and quantitative factors in determining whether or not 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 or production ceasing on a property for an extended period.   Auditing the Partnership’s impairment trigger assessment involved our subjective judgment because, in determining whether a triggering event occurred, significant uncertainty exists with judgments management utilizes regarding the likelihood of future production and the likelihood of potential contract renewals or modifications, which rely on information reported by the Partnership’s lessee operators.   How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Partnership’s impairment assessment process.  We tested controls over the Partnership’s process for identifying and evaluating potential triggers of impairment and related significant judgments.     To test the Partnership’s impairment assessment, our audit procedures included, among others, making inquiries of management (including personnel in operations) to understand changes in business, and evaluating the significant judgments used in the Partnership’s assessment. Specifically, we corroborated reserve information to new reserve 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 or regulatory changes and bankruptcy filings, that corroborates or contradicts management’s assessment.     /s/     Ernst & Young LLP   We have served as the Partnership’s auditor since 2002.   Houston, Texas March 2, 2023   42 Table of Contents   Report of Independent Registered Public Accounting Firm   Board of Managers and Members of Sisecam Wyoming LLC Atlanta, Georgia   Opinion on the Financial Statements   We have audited the accompanying balance sheet of Sisecam Wyoming LLC (the “Company”) as of December 31, 2022, the related statements of operations and comprehensive income, members' equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022, and the results of its operations and its cash flows for the year then ended, in conformity with 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 statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be 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 Exchange Commission 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 of our 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 of the 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 performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides 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 be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, 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 accounts or disclosures to which it relates.   43 Table of Contents   Agreements and Transactions with Affiliates   As presented in the financial statements and further as described in Notes 1, 2, 12, and 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 $53,924 thousand, $6,061 thousand, $15,136 thousand, and $19,261 thousand as of and for the year ended December 31, 2022.  As the Company is a subsidiary and investee within two different global group structures, agreements directly between the Company and other affiliates, or indirectly between affiliates the Company does not control, can have a significant impact on 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 completeness and accuracy of the Company's upstream affiliate relationships, transactions, and commitments and contingences originating outside of Sisecam USA and Ciner Enterprises, Inc. group and the impact of such matters on the financial statements as a critical audit matter. Auditing these elements involved especially challenging auditor judgement due to the nature and extent of audit effort and knowledge required to address these matters, including the extent of audit procedures performed to search for completeness, then identify, assess, and test the accuracy of these transactions.    The primary procedures we performed to address this critical audit matter included:     ● Testing the Company’s affiliate listing for the year ended December 31, 2022, including testing the completeness and accuracy of the Company’s affiliate relationships, transactions, and commitments and contingencies originating outside of the Sisecam USA and Ciner Enterprises, Inc. group by (i) reading and evaluating publicly available financial filings and news sources related to the Company and its affiliates outside of the Sisecam USA and Ciner Enterprises, Inc. group, (ii) inspecting director and executive officer questionnaires from certain of the Company’s directors and officers, (iii) searching the general ledger for transactions with affiliates and for a selection of transactions, tracing to source documents, (iv) considering sources of information that were gathered during the audit that could indicate that affiliate relationships, transactions, and commitments and contingencies exist, (v) inquiring of executive officers, key members of management, and certain members of the Board of Directors regarding affiliate relationships, transactions, and commitments and contingencies, and (vi) confirming with the Company's ultimate parent companies that the affiliate relationships, transactions, and commitments and contingencies identified and disclosed by the Company were complete and accurate.     /s/     BDO USA, LLP   We have served as the Company's auditor since 2022.   Atlanta, Georgia   March 2, 2023   44 Table of Contents   REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM   To the Board of Managers and Members of Sisecam Wyoming LLC Atlanta, Georgia   Opinion on the Financial Statements   We have audited the accompanying balance sheet of Sisecam Wyoming LLC (the "Company") as of December 31, 2021, the related statements of operations and comprehensive income, members' equity, and cash flows for each of the two years in the period 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, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2021, in conformity with 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 statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be 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 Exchange Commission 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 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 of our audits, 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 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 performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.   /s/ Deloitte & Touche LLP   Atlanta, Georgia March 15, 2022   We began serving as the Company's auditor in 2008.  In 2022 we became the predecessor auditor.   45 Table of Contents       NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED BALANCE SHEETS       December 31,   (In thousands, except unit data)   2022     2021   ASSETS                 Current assets                 Cash and cash equivalents   $ 39,091     $ 135,520   Accounts receivable, net     42,701       24,538   Other current assets, net     1,822       2,723   Total current assets   $ 83,614     $ 162,781   Land     24,008       24,008   Mineral rights, net     412,312       437,697   Intangible assets, net     14,713       16,130   Equity in unconsolidated investment     306,470       276,004   Long-term contract receivable, net     28,946       31,371   Other long-term assets, net     7,068       5,832   Total assets   $ 877,131     $ 953,823   LIABILITIES AND CAPITAL                 Current liabilities                 Accounts payable   $ 1,992     $ 1,956   Accrued liabilities     11,916       10,297   Accrued interest     989       1,213   Current portion of deferred revenue     6,256       11,817   Current portion of long-term debt, net     39,076       39,102   Total current liabilities   $ 60,229     $ 64,385   Deferred revenue     40,181       50,045   Long-term debt, net     129,205       394,443   Other non-current liabilities     5,472       5,018   Total liabilities   $ 235,087     $ 513,891   Commitments and contingencies (see Note 15)                     Class A Convertible Preferred Units ( 250,000 and 269,321 units issued and outstanding at December 31, 2022 and 2021, respectively, at $ 1,000 par value per unit; liquidation preference of $ 1,850 per unit at December 31, 2022 and 2021) (See Note 4)   $ 164,587     $ 183,908   Partners’ capital                 Common unitholders’ interest ( 12,505,996 and 12,351,306 units issued and outstanding at December 31, 2022 and 2021, respectively)   $ 404,799     $ 203,062   General partner’s interest     5,977       1,787   Warrant holders’ interest     47,964       47,964   Accumulated other comprehensive income     18,717       3,211   Total partners' capital   $ 477,457     $ 256,024   Total liabilities and partners' capital   $ 877,131     $ 953,823     The accompanying notes are an integral part of these consolidated financial statements.   46 Table of Contents     NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)       For the Year Ended December 31,   (In thousands, except per unit data)   2022     2021     2020   Revenues and other income                         Royalty and other mineral rights   $ 307,013     $ 185,196     $ 120,166   Transportation and processing services     21,072       9,052       8,845   Equity in earnings of Sisecam Wyoming     59,795       21,871       10,728   Gain on asset sales and disposals     1,082       245       581   Total revenues and other income   $ 388,962     $ 216,364     $ 140,320                             Operating expenses                         Operating and maintenance expenses   $ 34,903     $ 27,049     $ 24,795   Depreciation, depletion and amortization     22,519       19,075       9,198   General and administrative expenses     21,852       17,360       14,293   Asset impairments     4,457       5,102       135,885   Total operating expenses   $ 83,731     $ 68,586     $ 184,171                             Income (loss) from operations   $ 305,231     $ 147,778     $ ( 43,851 )                           Other expenses, net                         Interest expense, net   $ ( 26,274 )   $ ( 38,876 )   $ ( 40,968 ) Loss on extinguishment of debt     ( 10,465 )     —       —   Total other expenses, net   $ ( 36,739 )   $ ( 38,876 )   $ ( 40,968 )                           Net income (loss)   $ 268,492     $ 108,902     $ ( 84,819 ) Less: income attributable to preferred unitholders     ( 30,000 )     ( 31,609 )     ( 30,225 ) Net income (loss) attributable to common unitholders and the general partner   $ 238,492     $ 77,293     $ ( 115,044 )                           Net income (loss) attributable to common unitholders   $ 233,722     $ 75,747     $ ( 112,743 ) Net income (loss) attributable to the general partner     4,770       1,546       ( 2,301 )                           Net income (loss) per common unit (see Note 6)                         Basic   $ 18.72     $ 6.14     $ ( 9.20 ) Diluted     13.39       4.81       ( 9.20 )                           Net income (loss)   $ 268,492     $ 108,902     $ ( 84,819 ) Comprehensive income from unconsolidated investment and other     15,506       2,889       2,916   Comprehensive income (loss)   $ 283,998     $ 111,791     $ ( 81,903 )   The accompanying notes are an integral part of these consolidated financial statements.   47 Table of Contents     NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED STATEMENTS OF PARTNERS ’ CAPITAL                                       Accumulated     Partners' Capital                                                       Other     Excluding Non-     Non-               Common Unitholders     General     Warrant     Comprehensive     Controlling     Controlling     Total   (In thousands)   Units     Amounts     Partner     Holders     Income (Loss)     Interest     Interest     Capital   Balance at December 31, 2019     12,261     $ 271,471     $ 3,270     $ 66,816     $ ( 2,594 )   $ 338,963     $ ( 2,935 )   $ 336,028   Cumulative effect of adoption of accounting standard     —       ( 3,833 )     ( 78 )     —       —       ( 3,911 )     —       ( 3,911 ) Net loss (1)     —       ( 83,123 )     ( 1,696 )     —       —       ( 84,819 )     —       ( 84,819 ) Distributions to common unitholders and the general partner     —       ( 16,552 )     ( 338 )     —       —       ( 16,890 )     —       ( 16,890 ) Distributions to preferred unitholders     —       ( 29,511 )     ( 602 )     —       —       ( 30,113 )     —       ( 30,113 ) Acquisition of non-controlling interest in BRP     —       ( 4,747 )     ( 97 )     —       —       ( 4,844 )     2,935       ( 1,909 ) Unit-based awards amortization and vesting     —       3,222       —       —       —       3,222       —       3,222   Comprehensive income from unconsolidated investment and other     —       —       —       —       2,916       2,916       —       2,916   Balance at December 31, 2020     12,261     $ 136,927     $ 459     $ 66,816     $ 322     $ 204,524     $ —     $ 204,524   Net income (2)     —       106,724       2,178       —       —       108,902       —       108,902   Distributions to common unitholders and the general partner     —       ( 22,192 )     ( 453 )     —       —       ( 22,645 )     —       ( 22,645 ) Distributions to preferred unitholders     —       ( 30,519 )     ( 623 )     —       —       ( 31,142 )     —       ( 31,142 ) Issuance of unit-based awards     90       —       —       —       —       —       —       —   Unit-based awards amortization and vesting, net     —       2,647       —       —       —       2,647       —       2,647   Capital contribution     —       —       32       —       —       32       —       32   Warrant settlement     —       9,475       194       ( 18,852 )     —       ( 9,183 )     —       ( 9,183 ) Comprehensive income from unconsolidated investment and other     —       —       —       —       2,889       2,889       —       2,889   Balance at December 31, 2021     12,351     $ 203,062     $ 1,787     $ 47,964     $ 3,211     $ 256,024     $ —     $ 256,024   Net income (3)     —       263,122       5,370       —       —       268,492       —       268,492   Distributions to common unitholders and the general partner     —       ( 33,697 )     ( 687 )     —       —       ( 34,384 )     —       ( 34,384 ) Distributions to preferred unitholders     —       ( 29,653 )     ( 605 )     —       —       ( 30,258 )     —       ( 30,258 ) Issuance of unit-based awards     155       —       —       —       —       —       —       —   Unit-based awards amortization and vesting, net     —       1,965       —       —       —       1,965       —       1,965   Capital contribution     —       —       112       —       —       112       —       112   Comprehensive income from unconsolidated investment and other     —       —       —       —       15,506       15,506       —       15,506   Balance at December 31, 2022     12,506     $ 404,799     $ 5,977     $ 47,964     $ 18,717     $ 477,457     $ —     $ 477,457     (1) Net loss includes $30.2 million of income attributable to preferred unitholders that accumulated during the period, of which $29.6 million is allocated to the common unitholders and $0.6 million is allocated to the general partner.  (2) 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 the common unitholders and $0.6 million is allocated to the general partner. (3) 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 the common unitholders and $0.6 million is allocated to the general partner.   The accompanying notes are an integral part of these consolidated financial statements.   48 Table of Contents     NATURAL RESOURCE PARTNERS L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS       For the Year Ended December 31,   (In thousands)   2022     2021     2020   Cash flows from operating activities of continuing operations                         Net income (loss)   $ 268,492     $ 108,902     $ ( 84,819 ) Adjustments to reconcile net income (loss) to net cash provided by operating activities:                         Depreciation, depletion and amortization     22,519       19,075       9,198   Distributions from unconsolidated investment     44,835       11,270       14,210   Equity earnings from unconsolidated investment     ( 59,795 )     ( 21,871 )     ( 10,728 ) Gain on asset sales and disposals     ( 1,082 )     ( 245 )     ( 581 ) Loss on extinguishment of debt     10,465       —       —   Asset impairments     4,457       5,102       135,885   Bad debt expense     1,062       2,572       4,001   Unit-based compensation expense     5,773       4,039       3,570   Amortization of debt issuance costs and other     2,410       2,265       1,323   Change in operating assets and liabilities:                         Accounts receivable     ( 18,671 )     ( 14,415 )     12,853   Accounts payable     37       570       207   Accrued liabilities     935       3,020       ( 2,205 ) Accrued interest     ( 224 )     ( 501 )     ( 602 ) Deferred revenue     ( 15,424 )     307       9,733   Other items, net     1,049       1,714       ( 4,477 ) Net cash provided by operating activities of continuing operations   $ 266,838     $ 121,804     $ 87,568   Net cash provided by operating activities of discontinued operations     —       —       1,706   Net cash provided by operating activities   $ 266,838     $ 121,804     $ 89,274                             Cash flows from investing activities                         Proceeds from asset sales and disposals   $ 1,083     $ 249     $ 623   Return of long-term contract receivable     1,723       2,163       2,122   Acquisition of non-controlling interest in BRP     —       —       ( 1,000 ) Capital expenditures     ( 118 )     —       —   Net cash provided by investing activities of continuing operations   $ 2,688     $ 2,412     $ 1,745   Net cash used in investing activities of discontinued operations     —       —       ( 65 ) Net cash provided by investing activities   $ 2,688     $ 2,412     $ 1,680                             Cash flows from financing activities                         Debt borrowings   $ 70,000     $ —     $ —   Debt repayments     ( 339,396 )     ( 39,396 )     ( 46,176 ) Distributions to common unitholders and the general partner     ( 34,384 )     ( 22,645 )     ( 16,890 ) Distributions to preferred unitholders     ( 30,000 )     ( 15,571 )     ( 22,500 ) Redemption of preferred units paid-in-kind     ( 19,579 )     —       ( 3,863 ) Warrant settlement     —       ( 9,183 )     —   Acquisition of non-controlling interest in BRP     —       ( 1,000 )     —   Contributions from discontinued operations     —       —       1,641   Other items, net     ( 12,596 )     ( 691 )     —   Net cash used in financing activities of continuing operations   $ ( 365,955 )   $ ( 88,486 )   $ ( 87,788 ) Net cash used in financing activities of discontinued operations     —       —       ( 1,641 ) Net cash used in financing activities   $ ( 365,955 )   $ ( 88,486 )   $ ( 89,429 )                           Net increase (decrease) in cash and cash equivalents   $ ( 96,429 )   $ 35,730     $ 1,525   Cash and cash equivalents of continuing operations at beginning of period     135,520       99,790       98,265   Cash and cash equivalents at end of period   $ 39,091     $ 135,520     $ 99,790                             Supplemental cash flow information:                         Cash paid for interest   $ 25,265     $ 37,378     $ 39,830   Non-cash investing and financing activities:                         Plant, equipment, mineral rights and other funded with accounts payable or accrued liabilities   $ —     $ —     $ 970   Preferred unit distributions paid-in-kind     —       15,571       3,750     The accompanying notes are an integral part of these consolidated financial statements.   49 Table 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"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal and other natural resources and owns a non-controlling 49 % interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), a trona ore mining and soda ash production business. The Partnership is organized into two operating segments further described in Note 7. Segment Information . As used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or 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 one wholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Subject to the Board Representation and Observation Rights Agreement 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"), RCM is entitled to appoint the directors of the Board of Directors of GP Natural Resource Partners LLC (the "Board of Directors"). RCM has delegated the right to appoint one director to Blackstone.     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 the United 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 is not 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 had no impact on previously reported total assets, total liabilities, partners' capital, net income (loss) 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 reported amounts of assets and liabilities on the accompanying Consolidated Balance Sheets, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses on the accompanying Consolidated Statements of Comprehensive Income (Loss) 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 are used to compute depreciation, depletion and amortization and impairments of coal and aggregates properties and related intangible assets and commitments and contingencies.   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 be received 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 Value Measurements 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 other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. • Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial assets and liabilities whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.   50 Table 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 for current expected credit losses ("CECL") on its financial assets based on the loss-rate method. NRP assesses the likelihood of collection of its receivables utilizing historical loss rates, current market conditions that include the estimated impact of the global COVID- 19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers and properties. See Note 18. Credit Losses for more information. The total allowance related to accounts receivables included in accounts receivables, net on the Partnership's Consolidated Balance Sheets was $ 4.5  million a nd $ 3.2  million at December 31, 2022 and 2021 , respectively. The total allowance related to short-term notes receivables included in other current assets, net on the Partnership's C onsolidated Balance Sheets was  $ 0.0  million and $ 0.1  million at December 31, 2022 and 2021 , respectively. The total allowance related to the Partnership's long-term financing receivable included in long-term contract receivable, net on the Consolidated Balance Sheets was $ 1.0  million and $ 1.1  million at December 31, 2022 and 2021 , respectively. The Partnership recorded bad debt expense of $ 1.1  million, $ 2.6  million and $ 4.0  million included in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) for the year ended December 31, 2022, 2021 and 2020 , 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 aggregates mineral 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 estimated economic 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 than prevailing market rates, known as above-market contracts. The estimated fair value of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis by asset based upon minerals mined or 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-market contract term.   Asset Impairment   The Partnership has developed procedures to evaluate its long-lived assets, including intangible assets, for possible impairment periodically or whenever events or 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 events such 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 future performance and considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted 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 usually determined based upon the present 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 are consistent 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 carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices (Level 1 ), or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants (Level 3 ), plus market analysis of comparable 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, 2022 were $ 9.5  million of accrued employee costs and $ 2.4  million of other accrued liabilities. These amounts were $ 7.7  million and $ 2.6  million of accrued employee costs and other accrued liabilities, respectively, at December 31, 2021 . Other accrued liabilities at both December 31, 2022 and 2021 included property taxes.   51 Table 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 lessees having 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 of the 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 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 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 aggregates over the lease term. NRP then evaluated the likelihood that consideration it expected to receive from its lessees resulting from production would exceed consideration expected 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 lease term. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, NRP recognizes breakage revenue 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 lease term. 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 by lessees and the corresponding revenues from those sales. Also, included within oil and gas royalty revenues are lease bonus payments, which are generally paid upon the execution of a lease. The Partnership also has overriding royalty revenue interests in certain coal and aggregates mineral rights. Revenue from these interests is recognized 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's performance 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 as transportation 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 recognized straight-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 are reimbursable 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 NRP are included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).   Transportation and processing services revenues. The Partnership owns transportation and processing infrastructure that is leased to third parties for throughput fees. 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 contract modifications 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 or minimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within royalty and other mineral rights revenues on the Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognized prospectively 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 are recognized 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 revenue relates 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. The long-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-line basis 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 its production leases over the next twelve months, the Partnership is unable to estimate the current portion of deferred revenue.   52 Table 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 exercise significant influence over, but not control of, an investee. The Partnership's 49 % investment in Sisecam Wyoming is accounted for using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortized over its estimated useful life. The carrying value in Sisecam Wyoming is recognized in equity in unconsolidated investment on the Partnership's Consolidated Balance Sheets. 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 of Sisecam Wyoming on the Consolidated Statements of Comprehensive Income (Loss). The Partnership decreases its investment for its proportional share of distributions received from Sisecam Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are considered returns on investment and classified as operating cash inflows unless the cumulative distributions received exceed the Partnership's cumulative equity in earnings. The excess of cumulative distributions received over the Partnership's cumulative equity in earnings are considered returns of investment and classified as investing cash inflows.   Property Taxes   The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in operating and maintenance expenses and in royalty and other mineral rights revenues, respectively, on the Consolidated Statements of Comprehensive Income (Loss).   Unit-Based Compensation   The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units. Compensation cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. Forfeitures are recognized as they occur. Unit-based compensation expense for all awards is recognized in general and administrative expenses and operating and maintenance expenses on the Consolidated Statements of Comprehensive Income (Loss). See Note 16. Unit-Based Compensation for 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 the respective 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 on the Partnership's Consolidated Balance Sheets. Deferred financing costs related to the Partnership's note agreements are included as a direct deduction from the carrying 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. Net income (loss) for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial 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 an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.   53 Table 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)   2022     2021     2020   Coal royalty revenues   $ 226,956     $ 104,089     $ 51,868   Production lease minimum revenues     5,854       14,269       21,749   Minimum lease straight-line revenues     18,792       20,564       16,796   Carbon neutral initiative revenues     8,600       13,790       —   Property tax revenues     5,878       6,028       5,786   Wheelage revenues     13,961       10,065       7,025   Coal overriding royalty revenues     3,434       4,367       4,977   Lease amendment revenues     3,201       4,696       3,450   Aggregates royalty revenues     3,299       1,889       1,717   Oil and gas royalty revenues     16,161       4,506       5,816   Other revenues     877       933       982   Royalty and other mineral rights revenues   $ 307,013     $ 185,196     $ 120,166   Transportation and processing services revenues (1)     21,072       9,052       8,845   Total Mineral Rights segment revenues   $ 328,085     $ 194,248     $ 129,011     ( 1 ) Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $ 17.9  million , $ 5.4  million and $ 5.0  million for the year ended December 31, 2022, 2021 and 2020 , respectively. The remaining transportation and processing services revenues of $ 3.2  million, $ 3.6  million and $ 3.8  million for the year ended December 31, 2022, 2021 and 2020 , respectively, related to other NRP-owned infrastructure leased to and operated by third -party operators 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)   2022     2021   Receivables                 Accounts receivable, net   $ 39,004     $ 22,277   Other current assets, net (1)     —       769   Other long-term assets, net (2)     75       250                     Contract liabilities                 Current portion of deferred revenue   $ 6,256     $ 11,817   Deferred revenue     40,181       50,045     ( 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)   2022     2021     2020   Balance at beginning of period (current and non-current)   $ 61,862     $ 61,554     $ 51,821   Increase due to minimums and lease amendment fees     19,073       19,842       41,557   Recognition of previously deferred revenue     ( 34,498 )     ( 19,534 )     ( 31,824 ) Balance at end of period (current and non-current)   $ 46,437     $ 61,862     $ 61,554     The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty and overriding royalty leases are as follows as of December 31, 2022 (in thousands):   Lease Term (1)   Weighted Average Remaining Years     Annual Minimum Payments   0 - 5 years   2.2     $ 21,981   5 - 10 years   3.6       7,517   10+ years   12.7       27,221   Total   7.4     $ 56,719     ( 1 ) Lease term does not include renewal periods.   54 Table 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 certain entities controlled by funds affiliated with The Blackstone Group Inc. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree") (together the "preferred purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000 preferred 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 preferred units 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 in additional 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 units with 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 at any 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 date notice 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 the value 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 of conversion. 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 to redeem 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 Liquidation Value 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 be an 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 of redemption 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 the preferred 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 the notice 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 outstanding PIK 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 redemption price 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 the preferred 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's consolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership Agreement dated March 2, 2017 ( the "restated partnership agreement"), 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 or proposed 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 distribution above $ 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 units are 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 rights with respect to changes of the terms of the preferred units. In addition, Blackstone has certain approval rights over certain matters as identified in the restated partnership agreement. GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the minimum preferred unit threshold (as defined below). These approval rights are not transferrable without NRP's consent. In addition, the approval rights held by Blackstone and GoldenTree will 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 the closing 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 Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights, and Blackstone appointed one director and one 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 to which 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 registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion 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 90 days following the first issuance of any common units upon conversion of preferred units (the "registration deadlines"). In addition, the preferred unit and warrant registration rights agreement gives the preferred purchasers piggyback registration and demand underwritten offering rights under certain circumstances. The shelf registration statement to register the common units issuable upon exercise of the warrants became effective on April 20, 2017. If the shelf registration statement to register the common units issuable upon conversion of the preferred units is not effective by the applicable registration deadline, NRP will be required to pay the preferred purchasers liquidated damages in the amounts and upon the term set forth in the preferred unit and warrant registration rights agreement.   55 Table 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 be exercised 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 transaction issuance costs to the preferred units and warrants primarily on a pro-rata basis based on their relative inception date allocated values.   Subsequent Measurement   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 is probable of occurring. Once conversion or redemption becomes probable of occurring, the carrying amount of the preferred units will be accreted to their redemption value over the period from the date the feature is probable of occurring to the date the preferred units can first be converted or redeemed.    Activity related to the preferred units is as follows:       Units     Financial   (In thousands, except unit data)   Outstanding     Position   Balance at December 31, 2019     250,000     $ 164,587   Distribution paid-in-kind     3,750       3,750   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     In  February 2023, the Partnership received a notice from holders of the Class A Preferred Units exercising their right to either convert or redeem, at the election of NRP, an aggregate of 47,499 Class A Preferred Units. The Partnership chose to redeem the preferred units for $ 47.5 million in cash plus any accrued and unpaid distributions, utilizing cash on hand and borrowings under the Opco Credit Facility. Of the originally issued 250,000 Class A Preferred Units, 202,501 Class A Preferred Units remain outstanding as of the date of this report. The 30 -day VWAP ending on the business day prior to the redemption was $ 51.01 .   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 common units 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. Once warrant 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 common unitholders and general partner.   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 a net 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, 2019 and 2020     4,000,000     $ 66,816   Warrant settlement     ( 997,500 )     ( 18,852 ) Balance at December 31, 2021 and 2022     3,002,500     $ 47,964     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.   56 Table 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 both common 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 relative percentage interests in the Partnership. The general partner is entitled to receive 2 % of such distributions.   Income (loss) available to common unitholders and the general partner is adjusted by preferred unit distributions that accumulated during the period. NRP adjusted net income (loss) available to common unitholders and the general partner by $ 30.0 million, $ 31.6  million and $ 30.2  million during the year ended December 31, 2022, 2021 and 2020 , respectively as a result of accumulated preferred unit distributions earned during the period.   The following table shows the distributions declared and paid to common and preferred unitholders during the year ended December 31, 2022, 2021 and 2020 , respectively:           Cash Distributions     Paid-in-kind Distributions           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)   2022                                             February 2022   October 1 - December 31, 2021   $ 0.45     $ 5,672     $ 30.00     $ 7,500       —   February 2022 (2)   July 1 2020 - September 30, 2021     —       —       78.31       19,579       —   May 2022   January 1 - March 31, 2022     0.75       9,570       30.00       7,500       —   August 2022   April 1 - June 30, 2022     0.75       9,571       30.00       7,500       —   November 2022   July 1 - September 30, 2022     0.75       9,571       30.00       7,500       —                                                 2021                                             February 2021   October 1 - December 31, 2020   $ 0.45     $ 5,630     $ 15.00     $ 3,806       3,806   May 2021   January 1 - March 31, 2021     0.45       5,672       15.00       3,864       3,864   August 2021   April 1 - June 30, 2021     0.45       5,671       15.00       3,921       3,921   November 2021   July 1 - September 30, 2021     0.45       5,672       15.00       3,980       3,980                                                 2020                                             February 2020   October 1 - December 31, 2019   $ 0.45     $ 5,630     $ 30.00     $ 7,500       —   May 2020   January 1 - March 31, 2020     —       —       15.00       3,750       3,750   June 2020 (2)   January 1 - March 31, 2020     —       —       15.45       3,863       —   August 2020   April 1 - June 30, 2020     0.45       5,630       30.00       7,500       —   November 2020   July 1 - September 30, 2020     0.45       5,630       15.00       3,750       3,750     ( 1 ) Total common unit distribution includes the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest. ( 2 ) Redemption of preferred units paid in kind plus accrued interest.   57 Table of Contents   NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED     6. Net Income (Loss) Per Common Unit   Basic net income (loss) per common unit is computed by dividing net income (loss), after considering income attributable to preferred unitholders and the general partner’s general partner interest, by the weighted average number of common units outstanding. Diluted net income (loss) per common unit includes the effect of NRP's preferred units, warrants, and unvested unit-based awards 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 be converted at the beginning of the period, and the resulting common units are included in the denominator of the diluted net income (loss) per unit calculation for the period being presented. Distributions declared in the period and undeclared distributions on the preferred units that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. The calculation of diluted net income per common unit for the year ended December 31, 2022  and 2021 includes the assumed conversion of the preferred units. The calculation of diluted net loss per common unit for the years ended December 31, 2020 does not include the assumed conversion of the preferred units because the impact would have been anti-dilutive.   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 used to 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, 2022  includes the net settlement of warrants to purchase 0.75  million common units with a strike price of $ 22.81 and the net settlement of warrants to purchase 2.25  million 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 0.75  million common units with a strike price of $ 22.81 but does not include the net settlement of warrants to purchase 2.25  million common units with a strike price of $ 34.00 because the impact would have been anti-dilutive. The calculation of diluted net loss per common unit for the year ended December 31,  2020 does not include the net settlement of warrants to purchase 1.75 million common units with a strike price of $ 22.81 or the net settlement of warrants to purchase 2.25 million 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 (loss) per common unit computations and calculates basic and diluted net income (loss) per common unit:       For the Year Ended December 31,   (In thousands, except per unit data)   2022     2021     2020   Allocation of net income (loss)                         Net income (loss)   $ 268,492     $ 108,902     $ ( 84,819 ) Less: income attributable to preferred unitholders     ( 30,000 )     ( 31,609 )     ( 30,225 ) Net income (loss) attributable to common unitholders and the general partner   $ 238,492     $ 77,293     $ ( 115,044 ) Add (less): net loss (income) attributable to the general partner     ( 4,770 )     ( 1,546 )     2,301   Net income (loss) attributable to common unitholders   $ 233,722     $ 75,747     $ ( 112,743 )                           Basic net income (loss) per common unit                         Weighted average common units—basic     12,484       12,337       12,261   Basic net income (loss) per common unit   $ 18.72     $ 6.14     $ ( 9.20 )                           Diluted net income (loss) per common unit                         Weighted average common units—basic     12,484       12,337       12,261   Plus: dilutive effect of preferred units     6,176       9,604       —   Plus: dilutive effect of warrants     783       74       —   Plus: dilutive effect of unvested unit-based awards     210       178       —   Weighted average common units—diluted     19,653       22,193       12,261                             Net income (loss)   $ 268,492     $ 108,902     $ ( 84,819 ) Less: income attributable to preferred unitholders     —       —       ( 30,225 ) Diluted net income (loss) attributable to common unitholders and the general partner   $ 268,492     $ 108,902     $ ( 115,044 ) Add (less): diluted net loss (income) attributable to the general partner     ( 5,370 )     ( 2,178 )     2,301   Diluted net income (loss) attributable to common unitholders   $ 263,122     $ 106,724     $ ( 112,743 )                           Diluted net income (loss) per common unit   $ 13.39     $ 4.81     $ ( 9.20 )   58 Table 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 the manufacturing of steel, electricity and basic building materials, as well as opportunities for carbon sequestration and renewable energy. The Partnership is working to strategically 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 Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries.   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 the operating segments accordingly. These allocated costs generally include salaries and benefits, insurance, property taxes, legal, royalty, information technology and shared facilities services and are included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).   Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest and financing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment and are included in general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).   The following table summarizes certain financial information for each of the Partnership's business segments:       Operating Segments                   (In thousands)   Mineral Rights     Soda Ash     Corporate and Financing     Total   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   As of December 31, 2021                                 Total assets   $ 675,579     $ 276,004     $ 2,240     $ 953,823                                     For the Year Ended December 31, 2020                                 Revenues   $ 129,011     $ 10,728     $ —     $ 139,739   Gain on asset sales and disposals     581       —       —       581   Operating and maintenance expenses     24,610       185       —       24,795   Depreciation, depletion and amortization     9,198       —       —       9,198   General and administrative expenses     —       —       14,293       14,293   Asset impairments     135,885       —       —       135,885   Other expenses, net     79       —       40,889       40,968   Net income (loss)     ( 40,180 )     10,543       ( 55,182 )     ( 84,819 )   59 Table 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)   2022     2021     2020   Balance at beginning of period   $ 276,004     $ 262,514     $ 263,080   Income allocation to NRP’s equity interests (1)     64,712       26,979       15,205   Amortization of basis difference     ( 4,917 )     ( 5,108 )     ( 4,477 ) Other comprehensive income     15,506       2,889       2,916   Distribution     ( 44,835 )     ( 11,270 )     ( 14,210 ) Balance at end of period   $ 306,470     $ 276,004     $ 262,514     ( 1 ) Amounts reclassified into income out of accumulated other comprehensive income (loss) were ($ 6.8  million), $ 0.0  million and $ 1.7  million for the year ended December 31, 2022, 2021 and 2020 , 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 assets was $ 121.3 million and $ 126.3  million as of December 31, 2022 and 2021 , 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 basis difference 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 ended December 31, 2022 , 2021 , and 2020 :       For the Year Ended December 31,   (In thousands)   2022     2021     2020   Net sales   $ 720,120     $ 540,139     $ 392,231   Gross profit     162,575       80,550       54,838   Net income     132,065       55,059       31,030     The financial position of Sisecam Wyoming is summarized as follows:       December 31,   (In thousands)   2022     2021   Current assets   $ 340,437     $ 206,315   Noncurrent assets     292,915       297,210   Current liabilities     111,258       73,181   Noncurrent liabilities     144,290       124,749     60 Table 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,       2022     2021   (In thousands)   Carrying Value     Accumulated Depletion     Net Book Value     Carrying Value     Accumulated Depletion     Net Book Value   Coal properties   $ 661,812     $ ( 269,037 )   $ 392,775     $ 670,650     $ ( 253,503 )   $ 417,147   Aggregates properties     8,655       ( 3,410 )     5,245       8,747       ( 2,975 )     5,772   Oil and gas royalty properties     12,354       ( 9,600 )     2,754       12,354       ( 9,115 )     3,239   Other     13,150       ( 1,612 )     11,538       13,151       ( 1,612 )     11,539   Total mineral rights, net   $ 695,971     $ ( 283,659 )   $ 412,312     $ 704,902     $ ( 267,205 )   $ 437,697     Depletion expense related to the Partnership’s mineral rights is included in depreciation, depletion and amortization on its Consolidated Statements of Comprehensive Income (Loss) and totaled $ 20.9  million, $ 17.6  million and $ 8.8  million for the year ended December 31, 2022, 2021 and 2020 , respectively.   Impairment of Mineral Rights   During the years ended December 31, 2022, 2021 and 2020 , the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense included in asset impairments on the Consolidated Statements of Comprehensive Income (Loss) as follows:       For the Year Ended December 31,   (In thousands)   2022     2021     2020   Coal properties (1)   $ 4,365     $ 5,015     $ 114,302   Aggregates properties (2)     92       87       21,583   Total   $ 4,457     $ 5,102     $ 135,885     ( 1 ) The Partnership recorded $ 4.4  million of impairment expense during 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 value of 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 year ended December 31, 2021 primarily related to the full impairment of an asset resulting from a lease termination. The partnership recorded $ 114.3  million of impairment expense to impair certain assets during the year ended December 31, 2020 primarily related to weakened coal markets that resulted in termination of certain coal leases and changes to lessee mine plans resulting in permanent moves off certain of our coal properties. NRP compared the net book value of its coal properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted future cash flows, the Partnership recorded 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. Significant inputs used to determine fair value include estimates of future cash flows from coal 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 to the future realization of cash flows. ( 2 ) The Partnership recorded $ 0.1  million of aggregates royalty property impairments during the year ended December 31, 2022  and 2021. The Partnership recorded $ 21.6  million of aggregates royalty property impairments during the year ended December 31, 2020  primarily related to decreased oil and gas drilling activity which negatively impacted the outlook for NRP's frac sand properties. NRP compared the net book value of its aggregates and timber properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted cash flows, the Partnership recorded 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. Significant inputs 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 to the future realization of cash flows.   While the Partnership's impairment evaluation as of December 31, 2022 incorporated an estimated impact of the global COVID- 19 pandemic, there is significant uncertainty as to the severity and duration of this disruption. If the impact is worse than we currently estimate, an additional impairment charge may be recognized in future periods.       61 Table 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 Resources LLC ("Foresight") pursuant to which the Partnership receives royalty payments for coal sales and throughput fees for the transportation and processing of coal. The Partnership's intangible assets included on its Consolidated Balance Sheets are as follows:       December 31,   (In thousands)   2022     2021   Intangible assets at cost   $ 51,353     $ 51,353   Less: accumulated amortization     ( 36,640 )     ( 35,223 ) Total intangible assets, net   $ 14,713     $ 16,130     Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of Comprehensive Income (Loss) was $ 1.4  million, $ 1.3  million and $ 0.2  million for the year ended  December 31, 2022, 2021 and 2020 , respectively.   The estimates of amortization expense for the years ended December 31, as indicated below, are based on current mining plans and are subject to revision as those plans change in future periods.   (In thousands)   Estimated Amortization Expense   2023   $ 990   2024     1,133   2025     1,052   2026     1,052   2027     1,052     62 Table 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)   2022     2021   NRP LP debt:                 9.125 % senior notes, with semi-annual interest payments in June and December, due June 2025 issued at par ("2025 Senior Notes")   $ —     $ 300,000   Opco debt:                 Revolving credit facility   $ 70,000     $ —   Senior Notes                 5.55 % with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023   $ 2,366     $ 4,730   4.73 % with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023     6,004       12,008   5.82 % with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024     25,368       38,053   8.92 % with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024     8,023       12,035   5.03 % with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026     45,683       57,104   5.18 % with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026     11,643       14,554   Total Opco Senior Notes   $ 99,087     $ 138,484   Total debt at face value   $ 169,087     $ 438,484   Net unamortized debt issuance costs     ( 806 )     ( 4,939 ) Total debt, net   $ 168,281     $ 433,545   Less: current portion of long-term debt     ( 39,076 )     ( 39,102 ) Total long-term debt, net   $ 129,205     $ 394,443     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 of Comprehensive Income (Loss) 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 cash paid 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 following describes 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 matured on 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 time on 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 date of 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 2025 Senior 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 were issued 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 senior unsecured 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 all future 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 and future 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 subsidiaries guaranteed the 2025 Senior Notes. As of December 31, 2021, NRP was in compliance with the terms of the Indenture relating to their 2025 Senior Notes.   63 Table 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 than BRP LLC and NRP Trona LLC. As of December 31, 2022 and 2021 , Opco was in compliance with the terms of the financial covenants contained in its debt agreements.   Opco Credit Facility   In August 2022, the Partnership entered into the Fifth Amendment (the "Fifth Amendment") to the Opco Credit Facility (the "Opco Credit Facility"). The Fifth Amendment extended the term of the Opco Credit Facility until August 2027. Lender commitments under the Opco Credit Facility increased to $ 130.0 million.    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 margin ranging 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 had $ 70.0 million in borrowings outstanding under the Opco Credit Facility and $ 60.0 million of borrowing capacity as of December 31, 2022. The weighted average interest rate for the borrowings outstanding under the Opco Credit Facility for the year ended December 31, 2022 was 7.17 %. During the year ended December 31, 2021, the Partnership did not have any borrowings outstanding under the Opco Credit Facility and had $100.0 million in available borrowing capacity at December 31, 2021. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of  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 Credit Facility) 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, grant liens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability to acquire 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 course asset 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 repay its Senior Notes on a pro-rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility also contains customary events of default, including cross-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 o f $ 326.4  million and $ 345.0  million classified as mineral rights, net and other long-term assets, net on the Partnership’s Consolidated Balance Sheets as of December 31, 2022 and 2021 , respectively. The collateral includes ( 1 ) the equity interests in all of Opco’s wholly owned subsidiaries, other than BRP LLC 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 wholly owned 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-related infrastructure assets.   64 Table 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 December 31, 2022 and 2021 , the Opco Senior Notes had cumulative principal balances of $ 99.1  million and $ 138.5 million, respectively. Opco made mandatory principal payments on the Opco Senior Notes of $ 39.4 million, $ 39.4 million and $ 46.2 million during the year ended December 31, 2022, 2021 and 2020 , respectively.    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 most recent quarters; • not permit debt secured by certain liens and debt of subsidiaries to exceed 10 % of consolidated net tangible assets (as defined in the note purchase agreement); and • maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and 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 NRP Operating or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility and all renewals, amendments or restatements thereof), 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 of such 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 in the 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 in the amount of 2.00 % per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2022 .   In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepayment offers 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 of Opco 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-whole payment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior 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:       NRP LP     Opco           (In thousands)   Senior Notes     Senior Notes     Credit Facility     Total   2023   $ —     $ 39,396     $ —     $ 39,396   2024     —       31,028       —       31,028   2025     —       14,332       —       14,332   2026     —       14,331       —       14,331   2027     —       —       70,000       70,000   Thereafter     —       —       —       —       $ —     $ 99,087     $ 70,000     $ 169,087     65 Table 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 the Consolidated Balance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. The Partnership uses available market data and valuation 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,             2022     2021             Carrying     Estimated     Carrying     Estimated   (In thousands)   Fair Value Hierarchy Level     Value     Fair Value     Value     Fair Value   Debt:                                       NRP 2025 Senior Notes   1     $ —     $ —     $ 296,236     $ 300,000   Opco Senior Notes (1) (2)   3       98,281       96,060       137,309       138,484   Opco Credit Facility (3)   3       70,000       70,000       —       —   Assets:                                       Contract receivable, net (current and long-term) (4)   3     $ 31,371     $ 24,833     $ 33,612     $ 26,010     ( 1 ) The fair value of the Opco Senior Notes at December 31, 2022 was estimated by management utilizing the present value replacement method incorporating the interest rate of the Opco Credit Facility at December 31, 2022. ( 2 ) The fair value of the Opco Senior Notes at December 31, 2021  was estimated by management using quotations obtained for the NRP 2025 Senior Notes on the closing trading prices near period end, which were at  100 % of par value. ( 3 ) The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. ( 4 ) 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 a discount rate of 15 % at December 31, 2022 and 2021 .   NRP has embedded derivatives in the preferred units related to certain conversion options, redemption features and the change of control provision that are accounted for separately from the preferred units as assets and liabilities at fair value on the Partnership's Consolidated Balance Sheets. Level 3 valuation of the embedded derivatives are based on numerous factors including the likelihood of the event occurring. The embedded derivatives are revalued quarterly and changes in their fair value would be recorded in other expenses, net on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The embedded derivatives had zero value as of December 31, 2022 and 2021 .   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. Refer to Note 9. Mineral Rights, Net for additional disclosures related to the fair value associated with the impaired assets.   66 Table 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 the partnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, provide their services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. These QMC and WPPLP employee management service costs are presented as operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). 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 as operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).   Direct general and administrative expenses charged to the Partnership by QMC, WPPLP and QID are included on the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows:       For the Year Ended December 31,   (In thousands)   2022     2021     2020   Operating and maintenance expenses   $ 6,694     $ 6,543     $ 6,559   General and administrative expenses     4,864       4,611       4,611     The Partnership had accounts payable to QMC of $0.4  million on its Consolidated Balance Sheets at both  December 31, 2022 and 2021 and $ 1.0  million and $ 0.9  million of accounts payable to WPPLP at  December 31, 2022 and 2021 , respectively.   During the years ended December 31, 2022, 2021 and 2020 , the Partnership recognized $ 8.5  million, $ 3.3  million and $ 0.4  million in operating and maintenance expenses, respectively, on its Consolidated Statements of Comprehensive Income (Loss) related to an overriding royalty agreement with WPPLP.    Corbin J. Robertson, Jr. owns 85 % of the general partner of Great Northern Properties Limited Partnership ("GNP"), a privately held company primarily engaged in owning and managing mineral properties and surface leases. As of December 31, 2022  and 2021 Partnership had $ 0.03  million and $ 0.1  million, respectively of accounts receivable from GNP included in accounts receivable, net on its Consolidated Balance Sheets related to amounts collected for surface leases that belong to NRP.   67 Table 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,       2022     2021     2020   (In thousands)   Revenues     Percent     Revenues     Percent     Revenues     Percent   Alpha Metallurgical Resources, Inc. (1)   $ 102,352       26 %   $ 49,440       23 %   $ 33,227       24 % Foresight (1) (2)     65,597       17 %     37,366       17 %     35,704       26 %   ( 1 ) Revenues from Alpha Metallurgical Resources, Inc. and Foresight are included within the Partnership's Mineral Rights segment. ( 2 ) Revenues from Foresight in 2020 and 2021 were fixed as a result of the lease amendment the Partnership entered into with Foresight pursuant to which Foresight agreed to pay NRP fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreements between the Partnership and Foresight. Revenues from Foresight in  2022  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 cannot be 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 the Partnership has interests, are subject to federal and state environmental laws and regulations. See " Items 1. and 2. Business and Properties—Regulation and Environmental Matters ." As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership makes regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the 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 with environmental laws and regulations will have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31, 2022 . The Partnership is not associated with any material environmental contamination that may require remediation costs. However, the Partnership’s lessees are required to conduct reclamation work 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 costs associated 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.   68 Table 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 of 1,600,000 common units that are available for delivery by the Partnership pursuant to awards under the plan. The initial number of common units authorized for issuance pursuant 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 of approval 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 to administer 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 whole or 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 other person 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 awards under 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 is administered by the Compensation, Nominating and Governance Committee ("CNG Committee") of the Board of Directors, which determines the terms and conditions of awards 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 employees either 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 year period. 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 will continue 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 the distributions 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 but may be subject to forfeiture if the grantee ceases employment prior to vesting.   The Partnership's unit-based awards granted in 2022 , 2021 and  2020 were valued using the closing price of NRP's units as of the grant date. The grant date fair value of these awards granted during the year ended December 31, 2022, 2021 and 2020 were $ 7.9  million, $ 3.8  million and $ 3.5  million, respectively. Total unit-based compensation expense associated with these awards was $ 5.8  million, $ 4.0  million and $ 3.6  million for the year ended December 31, 2022, 2021 and 2020 , respectively, and is included in general and administrative expenses and operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The unamortized cost associated with unvested outstanding awards as of December 31, 2022 is $ 6.3  million, which is to be recognized over a weighted average period of 1.9  years. The unamortized cost associated with unvested outstanding awards as of  December 31, 2021 was $ 3.3  million.   A summary of the unit activity in the outstanding grants during 2022 is as follows:   (In thousands)   Common Units     Weighted Average Grant Date Fair value per Common Unit   Outstanding grants at January 1, 2022     411     $ 23.00   Granted     208     $ 38.29   Fully vested and issued     ( 233 )   $ 26.74   Outstanding at December 31, 2022     386     $ 28.96     69 Table 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. The infrastructure 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 Camp lease 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  million due to the Partnership in 2020  and 2021 was included in the fixed cash payments from Foresight resulting from contract modifications entered into during the second quarter of 2020 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 of coal 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 per year for the remainder of the renewed term.     18.      Credit Losses   The Partnership is exposed to credit losses through collection of its trade receivables resulting from contracts with customers and a long-term receivable resulting 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 the global COVID- 19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers and properties. Examples of these facts or circumstances include, but are not limited to, contract disputes or renegotiations with the customer and evaluation of short and long-term economic viability of the contracted property. For its long-term contract receivable, management reverts to the historical loss experience immediately after the reasonable and supportable forecast period ends.   As of December 31, 2022 and 2021 , NRP recorded the following current expected credit loss (“CECL”) related to its receivables and long-term contract receivable:       December 31,       2022     2021   (In thousands)   Gross     CECL Allowance     Net     Gross     CECL Allowance     Net   Receivables   $ 47,237     $ ( 4,461 )   $ 42,776     $ 28,869     $ ( 3,312 )   $ 25,557   Long-term contract receivable     29,984       ( 1,038 )     28,946       32,497       ( 1,126 )     31,371   Total   $ 77,221     $ ( 5,499 )   $ 71,722     $ 61,366     $ ( 4,438 )   $ 56,928     NRP recorded $ 1.1  million, $ 0.5  million and $ 0.0  million in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) related to the change in the CECL allowance during the year ended December 31, 2022, 2021 and 2020, respectively.   NRP has procedures in place to monitor its ongoing credit exposure through timely review of counterparty balances against contract terms and due dates, account and financing receivable reconciliations, bankruptcy monitoring, lessee audits and dispute resolution. The Partnership may employ legal counsel or collection specialists to pursue recovery of defaulted receivables.   70 Table of Contents   NATURAL RESOURCE PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED     19.      Leases   As of December 31, 2022 , the Partnership had one operating lease for an office building that is owned by WPPLP. On January 1, 2019, the Partnership entered into a new lease of the building with a five -year base term and five additional five -year renewal options. Upon lease commencement and as of December 31, 2022 and 2021 , the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liability on its Consolidated Balance Sheets using the present value of the future lease payments over 30 years. The Partnership's right-of-use asset and lease liability included within other long-term assets, net and other non-current liabilities, respectively, on its Consolidated Balance Sheets totaled $ 3.5 million at both December 31, 2022 and 2021 . During the years ended December 31, 2022, 2021 and 2020 , the Partnership incurred total operating lease expenses of $ 0.5 million, included in both operating and maintenance expenses and general and administrative expenses on its Consolidated Statements of Comprehensive Income (Loss).   The following table details the maturity analysis of the Partnership's operating lease liability and reconciles the undiscounted cash flows to the operating lease liability included on its Consolidated Balance Sheet:   Remaining Annual Lease Payments (In thousands)   December 31, 2022   2023   $ 483   2024     483   2025     483   2026     483   2027     483   After 2027     10,147   Total lease payments (1)   $ 12,562   Less: present value adjustment (2)     ( 9,092 ) Total operating lease liability   $ 3,470     ( 1 ) The remaining lease term of the Partnership's operating lease is 26  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 which represents the Partnership's estimated incremental borrowing rate under the lease. As the Partnership's lease does not provide an implicit rate, the Partnership estimated the incremental borrowing rate at the time the lease was entered into by utilizing the rate of the Partnership's secured debt and adjusting it for factors that reflect the profile of borrowing over the 30 -year expected lease term.   71 Table 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 the Exchange Act) as of December 31, 2022. This evaluation was performed under the supervision and with the participation