Natural Resource Partners (NRP) 10-K 2024 FY Annual report

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, 2024 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, 2024, was $889 million based on a closing price on June 28, 2024 of $89.64 per unit as reported on the New York Stock Exchange.

Documents incorporated by reference: None.

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	25
Item 1B.	Unresolved Staff Comments	37
Item 1C.	Cybersecurity	37
Item 3.	Legal Proceedings	37
Item 4.	Mine Safety Disclosures	37
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	[RESERVED]	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 8.	Financial Statements and Supplementary Data	51
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	82
Item 9A.	Controls and Procedures	82
Item 9B.	Other Information	84
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	84
PART III
Item 10.	Directors and Executive Officers of the Managing General Partner and Corporate Governance	85
Item 11.	Executive Compensation	89
Item 12.	Security Ownership of Certain Beneficial Owners and Management	99
Item 13.	Certain Relationships and Related Transactions, and Director Independence	100
Item 14.	Principal Accountant Fees and Services	104
PART IV
Item 15.	Exhibits, Financial Statement Schedules	106
Signatures		110

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

Statements included in this Annual Report on Form 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: future distributions on our common units; our business strategy; our liquidity and access to capital and financing sources; our financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projected production levels by our lessees; Sisecam Wyoming LLC’s ("Sisecam Wyoming's") trona mining and soda ash refinery operations; distributions from our soda ash joint venture; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and global and U.S. economic conditions.

These forward-looking statements speak only as of the date hereof and are made based upon 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 units 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.

• Global pandemics have in the past and may continue to adversely affect our business.

• Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material adverse effect on our business and results of operations.

• Changes to trade regulations, including trade restrictions, sanctions, tariffs, or duties, could significantly harm our 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. Thus, any changes in environmental laws and regulations or reinterpretations of enforcement policies, or in presidential administrations, that result in more stringent or costly obligations could adversely affect our performance.

• 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 reserve and resource data are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future, which could materially and adversely affect the quantities and value of Sisecam Wyoming's reserves and resources.

• 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.

Risks Related to Our Structure

• Unitholders may not be able to remove our general partner even if they wish to do so.

• We may issue additional common units or other equity securities without common unitholder approval, which could 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, 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 from their distributions and sale proceeds 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 Risk Factors

• 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

PART I

As used in this Annual Report on Form 10-K, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries.

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 (the "general partner" or "NRP GP"), has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC (the "managing general partner"), 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 ("RCM"), a limited liability company indirectly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. All members of the board of directors of the managing general partner (the "Board of Directors") are appointed by RCM.

The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited Partnership or Quintana Minerals Corporation, which are companies controlled by Mr. Robertson, Jr. These officers allocate varying percentages of their time to managing our operations. Neither our general partner, GP Natural Resource Partners LLC, nor any of their affiliates receive any management fee or other compensation in connection with the management of our business, 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 175 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

Segment and Geographic Information

The amount of 2024 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	$	249,872		93	%
Soda Ash		18,135		7	%
Total	$	268,007		100	%

The following map shows the approximate geographic distribution of our ownership footprint:

2

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 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 sales 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 that 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 in the United States 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 coal 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.

3

Coal Production Information

The following tables present the type of coal sales volumes by major coal region for the years ended December 31, 2024, 2023 and 2022:

For the Year Ended December 31, 2024
	Type of Coal
(Tons in thousands)	Thermal		Metallurgical		Total
Appalachia Basin
Northern		560		471		1,031
Central		1,782		12,355		14,137
Southern		—		2,661		2,661
Total Appalachia Basin		2,342		15,487		17,829
Illinois Basin		5,723		—		5,723
Northern Powder River Basin		2,826		—		2,826
Gulf Coast		1,342		—		1,342
Total		12,233		15,487		27,720

For the Year Ended December 31, 2023
	Type of Coal
(Tons in thousands)	Thermal		Metallurgical		Total
Appalachia Basin
Northern		794		351		1,145
Central		1,418		12,509		13,927
Southern		—		2,670		2,670
Total Appalachia Basin		2,212		15,530		17,742
Illinois Basin		8,119		—		8,119
Northern Powder River Basin		4,589		—		4,589
Gulf Coast		1,477		—		1,477
Total		16,397		15,530		31,927

For the Year Ended December 31, 2022
	Type of Coal
(Tons in thousands)	Thermal		Metallurgical		Total
Appalachia Basin
Northern		1,166		530		1,696
Central		1,186		12,460		13,646
Southern		93		1,691		1,784
Total Appalachia Basin		2,445		14,681		17,126
Illinois Basin		11,135		—		11,135
Northern Powder River Basin		4,288		—		4,288
Gulf Coast		385		—		385
Total		18,253		14,681		32,934

Major Coal Producing Properties

The following table provides a summary of our significant coal royalty properties for 2024 and is followed by additional information for each property:

Region	Property/Lease Name	Operator	Coal Type
Appalachia Basin
Central	Alpha-CAPP (VA)	Alpha Metallurgical Resources Inc.	Met
Central	Kepler	Alpha Metallurgical Resources Inc.	Met
Central	Marfork	Alpha Metallurgical Resources Inc.	Met
Central	Kingston	Alpha Metallurgical Resources Inc.	Met
Central	Elk Creek	Ramaco Royalty Company, LLC	Met
Southern	Oak Grove	Alabama Kanu 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	Westmoreland Mining LLC	Thermal

4

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 2024 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 2028 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 domestic and export metallurgical customers. The book value of this property was $44.0 million at December 31, 2024.

Below is a map of our Alpha-CAPP (VA) property:

Kepler.    The Kepler property is located in Wyoming County, West Virginia. Substantially all of the coal sold from this property in 2024 was metallurgical coal. We lease this property to a subsidiary of Alpha. Metallurgical 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.

Marfork.    The Marfork property is located in Boone and Raleigh Counties, West Virginia. Substantially all of the coal sold from this property in 2024 was metallurgical coal. We lease this property to a subsidiary of Alpha. Metallurgical coal is produced from underground mines and transported by belt or truck to the preparation plant on the property. Coal is shipped via the CSX railroad to both domestic and export metallurgical customers.

Kingston.    The Kingston property is located in Fayette and Raleigh Counties, West Virginia. Substantially all of the coal sold from this property in 2024 was metallurgical coal. We lease this property to a subsidiary of Alpha. Metallurgical coal is produced from surface and underground mines and transported by belt or truck to nearby preparation plants, including the Marfork complex. Coal is shipped via the CSX and Norfolk Southern railroads to both domestic and export metallurgical customers.

Elk Creek.    The Elk Creek property is located in Logan and Wyoming Counties, West Virginia. Substantially all of the coal sold from this property in 2024 was metallurgical coal. 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.

5

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 Alabama Kanu Holdings, LLC ("Alabama Kanu"). Previous operators of this property were Hatfield Metallurgical Coal Holdings, LLC, Murray Metallurgical Coal Holdings LLC, Mission Coal, LLC, and Seneca Resources, LLC. The current lease with Alabama Kanu expires in 2029 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 primarily export customers but can be shipped to domestic customers as well. The book value of this property was $3.0 million at December 31, 2024.

Below is a map of our Oak Grove property: 

6

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 $34.4 million at December 31, 2024.

Below is a map of our Williamson property:

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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 utility customers. The book value of this property was $203.9 million at December 31, 2024.

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 and remains in temporary cessation of production. 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 instead pay an annual Macoupin fee of $2.0 million to NRP each year through 2026. 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, 2027, 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, 2027, 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 applicable to the Macoupin mine.

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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 $10.9 million in revenue related to our coal transportation and processing assets during the year ended December 31, 2024. 

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

Our oil and gas properties are predominately located in Louisiana and during 2024, we received $8.6 million in oil and gas royalty revenues. Our various industrial mineral and construction aggregates properties are located across the United States and include minerals such as limestone, frac sand, 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 2024, we received $2.9 million in aggregates royalty revenues, including overriding royalty revenues. 

Carbon Neutral Initiatives

We continue to explore and identify carbon neutral revenue sources across our large portfolio of surface, mineral, and timber assets, including the sequestration of carbon dioxide ("CO₂") in our underground pore space and standing forests, lithium production, 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 provides 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 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. We have the ability to harvest and sell future timber growth and in 2023, we sold carbon offset credits related to 2022 growth for $0.6 million.

Additionally, during 2024 we received approximately $13.4 million from a third party related to its creation of California Air Resources Board carbon offset credits from our properties.

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 or direct air capture capability, and the appropriate form of legal title that grants the acreage owner the right to sequester emissions in the subsurface. The demand for CCUS may be impacted by changes in the regulatory climate, including changes in environmental regulations. Changes in presidential administrations, or at a congressional level may result in periodic increases or decreases in CCUS projects. 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 CO₂ 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 CO₂; however, we were notified that this agreement would not be renewed for another lease term and has been terminated as per the lessee's rights in the agreement. In October of 2022, we announced our second subsurface CO₂ 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 CO₂.

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.

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Soda Ash Segment

We own a 49% non-controlling equity interest in Sisecam Wyoming. Sisecam Chemicals Wyoming LLC ("SCW LLC") is the direct owner of 51% of Sisecam Wyoming. SCW LLC, our operating partner, controls and operates Sisecam Wyoming. SCW LLC is 100% owned by Sisecam Chemicals Resources LLC ("Sisecam Chemicals,") which is 100% owned by Sisecam USA Inc. ("Sisecam USA"). Sisecam USA is a direct wholly-owned subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş, a Turkish Corporation ("Şişecam Parent"), which is an approximately 51%-owned subsidiary of Turkiye Is Bankasi Turkiye Is Bankasi ("Isbank"). Şişecam Parent is a global company operating in soda ash, chromium chemicals, flat glass, auto glass, glassware glass packaging and glass fiber sectors. Şişecam Parent was founded over 88 years ago, is based in Turkey and is one of the largest industrial publicly-listed companies on the Istanbul exchange. With production facilities in several continents and in several countries, Sisecam is one of the largest glass and chemicals producers in the world. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries. As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine 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.

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 consist of leased and licensed subsurface mining areas in Wyoming. The facility is accessible by both road and rail. Sisecam Wyoming uses large continuous mining machines and 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.

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The following map provides an aerial overview of the Green River Basin surface operations:

11

The following map shows the known sodium leasing area within the Green River Basin, including the boundaries of Sisecam Wyoming's leased and licensed subsurface mining:

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The Green River Basin geological formation holds one of the largest and purest known deposits of trona ore in the world. Sisecam Wyoming's reserves contain trona deposits having a purity between 80% and 89% by weight, which means that insoluble impurities and water make up approximately 11% to 20% of Sisecam Wyoming's trona.

Sisecam Wyoming's mining leases and license are located in two mining beds, designated by the U.S. Geological Survey as beds 24 and 25, at depths of 850 to 800 feet near their shaft locations, respectively, below the surface. Mining these beds affords Sisecam Wyoming several competitive advantages. First, the depth of Sisecam Wyoming's beds is shallower than other actively mined beds in the Green River Basin, which allows them to use a continuous mining technique to mine trona and roof bolt the ceiling simultaneously. In addition, mining two beds that are on top of one another allows for production efficiencies because Sisecam Wyoming is able to use a single hoisting shaft to service both beds.

The following graphic shows a cross-section of the strategic areas of the Green River Basin where Sisecam Wyoming mines trona:

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. The facility is in good working condition and has been in service for more than 60 years.

Shipping and Logistics. For the year ended December 31, 2024, 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, 2024, 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 2024, Sisecam Wyoming had no shortfall payments and does not expect to make any such payments in the future. A leased fleet of hopper cars serve as dedicated modes 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. 

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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. For customers in North America, Sisecam Chemicals typically enters into contracts on Sisecam Wyoming’s behalf with terms ranging from one to three years. 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

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 four full years directly managing its international sales, marketing and logistics activities since exiting American Natural Soda Ash Corporation ("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, 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), and other private paarties which provide for royalties based upon production volume. 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.

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, SCW LLC, 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.

Sisecam Wyoming produced 2.5 million, 2.6 million and 2.8 million short tons of soda ash (of which the Partnership's interest is 1.2 million, 1.3 million and 1.4 million short tons of soda ash) during the year ended December 31, 2024, 2023 and 2022, respectively. Sisecam Wyoming sold 2.5 million, 2.7 million and 2.7 million short tons of soda ash (of which the Partnership's interest is 1.2 million, 1.3 million and 1.3 million short tons of soda ash) during the year ended December 31, 2024, 2023 and 2022, respectively. Sisecam Wyoming had net sales of $578.1 million, $773.6 million and $720.1 million (of which the Partnership's interest is $283.3 million, $379.1 million and $352.8 million) during the year ended December 31, 2024, 2023 and 2022, respectively. 

Cautionary Note to Investors Regarding Estimates Of Measured, Indicated And Inferred Resources And Proven And Probable Mineral Reserves

We are subject to the reporting requirements of the Exchange Act governed by S-K 1300 that aim to convey an appropriate level of confidence in the disclosures being reported. In our public filings we disclose proven and probable reserves and measured, indicated and inferred resources, each as defined in S-K 1300. The estimation of measured resources and indicated resources involve greater uncertainty as to their existence and economic feasibility than the estimation of proven and probable reserves, and therefore investors are cautioned not to assume that all or any part of measured or indicated resources will ever be converted into S-K 1300-compliant reserves. The estimation of inferred resources involves far greater uncertainty as to their existence and economic viability than the estimation of other categories of resources, and therefore it cannot be assumed that all or any part of inferred resources will ever be upgraded to a higher category. Therefore, investors are cautioned not to assume that all or any part of inferred resources exist, or that they can be mined legally or economically.

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Trona Resources and Trona Reserves

Information concerning Sisecam Wyoming's mining property and estimated mineral resources and mineral reserves in this Form 10-K has been prepared in accordance with the requirements of S-K 1300 which requires us to disclose Sisecam Wyoming's mineral resources, in addition to Sisecam Wyoming's mineral reserves, at Sisecam Wyoming's mining property as of the end of our most recently completed fiscal year. The information that follows is derived, for the most part, from, and in some instances is an extract from the technical report summary prepared by Hollberg Professional Group (“HPG”) in compliance with Item 601(b)(96) and S-K 1300 completed on February 27, 2025 (the “2024 TRS”). Portions of the following information are based on assumptions, qualifications and procedures, that are not fully described herein. Reference should be made to the full text of the technical report summary prepared by HPG attached as Exhibit 96.1 and incorporated herein by reference and made a part of this Form 10-K. We have used the term “trona” as in “trona resources” and “trona reserves” interchangeably with “mineral.”

HPG has conducted an independent technical review of the lands held by Sisecam Chemicals referred to as the “Big Island Mine,” which is located in the area commonly referred to as the Known Sodium Lease Area (the “KSLA”) near the town of Green River, Sweetwater County. The KSLA is where trona thickness exceeds 1-meter, extends for over 300 km2, and is greater than 80% grade. The U.S. Geological Survey recognizes 25 trona beds of economic importance (at least 1 meter in thickness and 300 km2 in areal extent) within the Green River Basin. Identified in ascending order, the trona beds are numbered 1 through 25 from the oldest (stratigraphically lowest) to the youngest (stratigraphically highest). Sisecam Wyoming has approximately 23,999 acres of trona under lease made up of approximately 8,094 Federal acres, 2,986 State acres, and 12,919 private acres. Sisecam Chemicals has mineral resources and mineable reserves in the shallowest mechanically mineable Trona beds 24 and 25, at depths of 850 and 800 feet below the surface, respectively, at our mine shaft locations. See also certain maps and graphics of Sisecam Wyoming's property above.

HPG estimated the total of the Big Island Mine’s remaining leased and licensed proven and probable trona reserves as 217.7 million short tons (of which the Partnership’s interest is 106.7 million short tons) as of December 31, 2024, compared to 211.3 million short tons (of which the Partnership’s interest was 103.5 million short tons) as of December 31, 2023 and the total of the measured and indicated in-place trona resources exclusive of reserves as 153.3 million short tons (of which the Partnership’s interest is 75.1 million short tons) as of December 31, 2024, compared to 162.3 million short tons (of which the Partnership's interest was 79.5 million short tons) as of December 31, 2023. As of December 31, 2024, the increase of 6.4 million short tons of the Big Island Mine’s proven and probable trona reserves, or 3.0%, as compared to December 31, 2023 is due to to the net result of reductions from mining activities, additions due to lease acquisition and additions due to geologic model modifications. The cutoff grade of greater than 75% trona and thickness greater than 6 feet is applied to estimate the trona resources based upon successful mining and processing of the lower grade trona beds 19, 20 and 21 which were considered viable mining prospects by Texas Gulf Soda Ash (“TGSA”). The mineral resource inclusive of the mineral reserves is that portion of the ore body that is considered either economically viable for mining and can be converted to reserves or of economic interest but considered outside the current economic limits. This is the material considered of economic interest that has the potential to be converted to reserves. Sisecam Wyoming's trona resources are categorized as “Measured mineral resources,” “Indicated mineral resources,” and “Inferred mineral resources,” which are defined as follows:

• Measured mineral resources - Mineral resources for which quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a measured mineral resource is sufficient to allow a qualified person to apply modifying factors, as defined in this section, in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit. Because a measured mineral resource has a higher level of confidence than the level of confidence of either an indicated mineral resource or an inferred mineral resource, a measured mineral resource may be converted to a proven mineral reserve or to a probable mineral reserve.

• Indicated mineral resources - Mineral resources for which quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. The level of geological certainty associated with an indicated mineral resource is sufficient to allow a qualified person to apply the modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. Because an indicated mineral resource has a lower level of confidence than the level of confidence of a measured mineral resource, an indicated mineral resource may only be converted to a probable mineral reserve. (The modifying factors are the factors that a qualified person must apply to indicated and measured mineral resources and then evaluate in order to establish the economic viability of mineral reserves. A qualified person must apply and evaluate modifying factors to convert measured and indicated mineral resources to proven and probable mineral reserves. These factors include but are not restricted to mining; processing; metallurgical; infrastructure; economic; marketing; legal; environmental compliance; plans, negotiations, or agreements with local individuals or groups; and governmental factors. The number, type and specific characteristics of the modifying factors applied will necessarily be a function of and depend upon the mineral, mine, property, or project.)

• Inferred mineral resources - Mineral resources for which quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. The level of geological uncertainty associated with an inferred mineral resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Because an inferred mineral resource has the lowest level of geological confidence of all mineral resources, which prevents the application of the modifying factors in a manner useful for evaluation of economic viability, an inferred mineral resource may not be considered when assessing the economic viability of a mining project and may not be converted to a mineral reserve.

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The following is a summary of the recoverable trona reserves for beds 24 and 25 as of December 31, 2024:

(in millions of short tons except percentage) (1) (2)
Reserve Category	Proven mineral reserves			Probable mineral reserves			Total mineral reserves
	Amount	Grade (1)		Amount	Grade (1)		Amount	Grade (1)
Lower Bed 24	69.7	85.9	%	75.2	85.6	%	145.0	85.8	%
Upper Bed 25	39.5	85.6	%	33.3	84.8	%	72.8	85.3	%
Total (3) (4) (5)	109.2	85.8	%	108.5	85.3	%	217.7	85.6	%

(1)	Numbers have been rounded; totals may not sum due to rounding.
(2)	Based on a 7-foot minimum thickness and an 85% minimum grade cut-off.
(3)	The point of reference is run-of-mine (ROM) ore delivered to the processing facilities including mining losses and dilution.
(4)	Mineral reserves are current as of December 31, 2024, using the definitions in S-K 1300.
(5)	Mineral reserves are reported on a 100% ownership basis. Sisecam Wyoming is owned 51% by SCW LLC and 49% by NRP.

Sisecam Wyoming's reserves are subject to leases with the State of Wyoming and the U.S. Bureau of Land Management and a license with Sweetwater Royalties LLC.

The following table presents Sisecam Wyoming's estimated proven and probable trona reserves by license and leases as of December 31, 2024:

(in millions of short tons except percentage) (1) (2)
Reserve Category	Proven mineral reserves			Probable mineral reserves			Total mineral reserves
	Amount	Grade (1)		Amount	Grade (1)		Amount	Grade (1)
License with Sweetwater Royalties LLC	55.7	85.9	%	55.1	85.3	%	110.8	85.6	%
Leases with the U.S. Government	45.6	85.6	%	34.6	85.3	%	80.2	85.4	%
Leases with the State of Wyoming	8.0	86.7	%	18.8	85.9	%	26.8	86.1	%
Total (3) (4) (5)	109.2	85.8	%	108.5	85.3	%	217.7	85.6	%

(1)	Numbers have been rounded; totals may not sum due to rounding.
(2)	Based on a 7-foot minimum thickness and an 85% minimum grade cut-off.
(3)	The point of reference is ROM ore delivered to the processing facilities including mining losses and dilution.
(4)	Mineral reserves are current as of December 31, 2024, using the definitions in S-K 1300.
(5)	Mineral reserves are reported on a 100% ownership basis. Sisecam Wyoming is owned 51% by SCW LLC and 49% by NRP.

The following is a summary of the measured, indicated, and inferred mineral resources exclusive of reserves for trona beds 24 and 25 as of December 31, 2024:

(in millions of short tons except percentage and thickness) (1) (2)
Reserve Category	Measured mineral resources			Indicated mineral resources			Measured + Indicated mineral resources				Inferred mineral resources
	Amount	Grade (1)		Amount	Grade (1)		Amount	Grade (1)		Thickness (ft)	Amount	Grade (1)
Lower Bed 24	45.4	88.5	%	53.6	86.6	%	99.1	87.5	%	8.6	—	—	%
Upper Bed 25	29.3	84.9	%	25.0	86.2	%	54.3	85.5	%	7.9	—	—	%
Total (3) (4) (5)	74.7	87.1	%	78.7	86.5	%	153.3	86.8	%	8.3	—	—	%

(1)	Numbers have been rounded; totals may not sum due to rounding.
(2)	Based on a 6-foot minimum thickness and a 75% minimum grade cut-off.
(3)	The point of reference is in-place inclusive of impurities and insoluble content.
(4)	Mineral reserves are current as of December 31, 2024, using the definitions in S-K 1300.
(5)	Mineral reserves are reported on a 100% ownership basis. Sisecam Wyoming is owned 51% by SCW LLC and 49% by NRP.

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HPG estimated proven and probable reserves of approximately 217.7 million short tons of trona (of which the Partnership’s interest is 106.7 million short tons), which is equivalent to 118.0 million short tons of soda ash as of December 31, 2024 (of which the Partnership’s interest is 57.8 million short tons of soda ash). Based on Sisecam Wyoming's current mining rate of approximately 4.3 million short tons of trona per year, Sisecam Wyoming has enough proven and probable trona reserves to continue mining trona using current methods for approximately 50 years.

The mineral reserve is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted. Sisecam Wyoming's trona reserves are categorized as “Proven mineral reserves” and “Probable mineral reserves,” which are defined as follows:

• Proven mineral reserves - The economically mineable part of a measured mineral resource and can only result from conversion of a measured mineral resource.

• Probable mineral reserves - The economically mineable part of an indicated and, in some cases, a measured mineral resource.

In determining the reserve parameters and assumptions HPG considered the following circumstances:

• Sisecam Wyoming’s 60-year long history and economics of mining the deposit and producing soda ash;

◦ The 183.3 million short tons (“Mst”) of trona ore produced from these two beds;

• The projected long life of the mine and resulting likely change in economics, mining, and processing methods over its projected 40 plus-year mine life (considering increased production over the current production rates) used in this technical summary. This 40 plus-year mine life consideration is based on the specific assumptions in this technical summary, including assumptions related to projected timing and estimated cost of two-seam mining, timing of related capital expenditures and sales price projections;

• Sisecam Wyoming’s current processing facilities’ capabilities and projected future changes to these facilities;

• The economics associated with Sisecam Wyoming’s current mining equipment and history of “high grading” the thickest portions of the deposit;

• Sisecam Wyoming’s current mining equipment limitations and required future changes to these systems; and

• HPG’s knowledge of operating and managing other trona and potash mines.

In determining whether the reserves meet these economic standards, HPG made certain assumptions regarding the remaining life of the Big Island Mine, including, among other things, that:

• the cost of products sold per short ton will remain consistent with Sisecam Wyoming’s cost of products sold for the five years ended December 31, 2024;

• the weighted average net sales per short ton FOB plant, $165/ton, based on USGS pricing and historical pricing provided by Sisecam Wyoming;

• Sisecam Wyoming’s mining costs will remain consistent with the five years ended December 31, 2024, until they begin two-seam mining, at which time mining costs for the two-seam mining tonnage could increase by as much as 30%;

• Sisecam Wyoming’s processing costs will remain consistent with the five years ended December 31, 2024, and rise in 10-years to account for lower grade material;

• Sisecam Wyoming will achieve an annual mining rate of approximately 4.3 million short tons of trona in 2025 and beyond;

• Sisecam Wyoming will process soda ash with a 90% rate of recovery, without accounting for the deca rehydration process;

• the ore to ash ratio for the stated trona reserves is 1.835:1.0 (short tons of trona run-of-mine to short tons of soda ash);

• The run-of-mine ore estimate contains dilution from the mining process;

• Sisecam Wyoming will continue to conduct only conventional mining using the room and pillar method and a non-subsidence mine design;

• Sisecam Wyoming will, in approximately 10 years, make necessary modifications to the processing facilities to allow localized mining of 75% ore grade in areas where the floor seam or insoluble disruptions have moved up into the mining horizon causing mining to be halted early due to processing facility limitations;

• Sisecam Wyoming will, in approximately 20 years, make necessary equipment modifications to operate at a seam height of 7-feet, the current mining limit is 9-feet;

• Sisecam Wyoming has and will continue to have valid leases and license in place with respect to the reserves, and that these leases and license can be renewed for the life of the mine based on their extensive history of renewing leases and license;

• Sisecam Wyoming has and will continue to have the necessary permits to conduct mining operations with respect to the reserves; and

• Sisecam Wyoming will maintain the necessary tailings storage capacity to maintain tailings disposal between the mine and surface placement for the life-of-mine.

Sisecam Wyoming's estimates of mineral resources and mineral reserves will change from time to time as a result of mining activities, analysis of new engineering and geologic data, modification of mining plans or mining methods and other factors. For additional information, see "Item 1A. Risk Factors, Risks Related to Our Business” for more information regarding risks surrounding Sisecam Wyoming's reserves.

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Internal Controls Disclosure over Trona Resources and Trona Reserves

Sisecam Wyoming has internal controls over the trona resources and trona reserves estimation processes that result in reasonable and reliable estimates aligned with industry practice and reporting regulations. Annually, qualified persons and other Sisecam Wyoming employees review the estimates of trona resources and trona reserves and the supporting documentation, and based on their review of such information recommend approval to use the trona resources and trona reserves estimates to Sisecam Wyoming senior management. Sisecam Wyoming's controls utilize management systems, including, but not limited to, standardized procedures, workflow processes, supervision and management approval, internal and external reviews and audits, reconciliations, and data security covering record keeping, chain of custody and data storage. Sisecam Wyoming's systems also cover sample preparation and analysis, data verification, trona processing, metallurgical testing, recovery estimation, mine design and sequencing, and trona resource and reserve evaluations, with environmental, social and regulatory considerations.

These controls and other methods help to validate the reasonableness of the estimates. The effectiveness of the controls is reviewed periodically to address changes in conditions and the degree of compliance with policies and procedures. For additional information regarding the risks associated with Sisecam Wyoming's estimates of trona resources and reserves, see "Item 1A. Risk Factors, Risks Related to Our Business—Sisecam Wyoming's reserve and resource data are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future, which could materially and adversely affect the quantities and value of Sisecam Wyoming's reserves and resources.”

The technical data underlying the mineral resources and reserves estimates included in this Annual Report on Form 10-K, including the internal controls for determining and reporting such mineral resources and reserves estimates, are maintained by Sisecam Wyoming, and our agreements with Sisecam Wyoming do not give us (i) access to such underlying technical data sufficient to specifically confirm the opinion of the qualified person with respect to such resources and reserves or (ii) the ability to monitor or enforce Sisecam Wyoming's internal controls for determining and reporting such resources and reserves. Sisecam Wyoming has, however, made representations to us and the qualified person that it does not have reason to believe that the underlying technical data is materially misleading, and that Sisecam Wyoming's internal controls were applied to the mineral resource and reserve information contained in the report. We are providing this information because it represents the information that we have in our possession and we do not have a reasonable ground to believe that it is inaccurate, but we caution investors that we have relied on the qualified person and Sisecam Wyoming with respect to the preparation of the mineral resources and reserves estimates included in this report and are not able to independently verify its accuracy. Investors are cautioned to consider such risks when reviewing the mineral resources and reserves estimates included in this report.

Significant Customers

We have a significant concentration of revenues from Alpha, with total revenues of $67.7 million in 2024 from several different mining operations, including wheelage revenues and coal overriding royalty revenues. We also have a significant concentration of revenues with Foresight and its subsidiaries, with total revenues of $39.2 million in 2024 from all of their mining operations, including transportation and processing services revenues, coal overriding royalty revenues and wheelage revenues. We also have a significant concentration of revenues with Alabama Kanu with total revenues of $29.5 million in 2024 from one mining operation, including overriding royalty 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.

Title to Property

We owned substantially all of our coal and aggregates mineral rights in fee as of December 31, 2024. 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.

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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 National Ambient Air Quality Standards ("NAAQS") for ozone. However, on August 21, 2023, the EPA announced a new review of the ozone NAAQS in combination with its reconsideration of EPA's December 2020 decision to retain the 2015 NAAQS. The EPA’s review remains ongoing and it is uncertain when the EPA will complete its review. More recently, in December 2024, the EPA issued a rule to revise the secondary NAAQS for sulfur oxides, but retained without revision the secondary standards for oxides of nitrogen and particulate matter. In May 2024, the EPA published a final rule to amend the MATS rule, which further limits the emission of non-mercury hazardous air pollutant metals from existing coal-fired power plants, tightens the emission standard for mercury for existing lignite-fired power plants, and strengthens emissions monitoring and compliance requirements. This final rule was challenged by various states and industry groups in the U.S. Court of Appeals for the D.C. Circuit. Although the lawsuit remains ongoing, the Supreme Court denied the challengers’ request for a stay, so the implementation of the rule will continue as promulgated. Although the impacts of the May 2024 final rule are unknown, the MATS rule program has already forced electric power generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units and many electric power generators have already announced retirements due to the uncertainty surrounding the MATS rule. 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.

The EPA’s regulation of methane under the Clean Air Act may also affect oil and gas production on properties in which we hold oil and gas interests. In December 2023, the EPA issued its methane rules, known as OOOOb and OOOOc, that establish new source and first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. The final rules are currently being challenged by 23 states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit, although OOOOb is already in effect. However, the new administration might take action to repeal or modify the methane rules though we cannot predict whether such action will occur or its timing. To the extent the methane rules are implemented as originally promulgated, compliance with the new rules may affect the amount oil & gas companies owe under the Inflation Reduction Act, which amended the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2026 and thereafter. In November 2024, the EPA finalized a rule, applicable to oil and gas facilities that emit more than 25,000 metric tons of CO₂ per year, to implement the methane emissions fee provisions of the Inflation Reduction Act. We cannot predict whether, how, or when the new administration might take action to revise or repeal the methane fee rule. Additionally, Congress may take actions to repeal or revise the Inflation Reduction Act, including with respect to the methane emissions fee, which timing or outcome similarly cannot be predicted. To the extent that the methane emissions fee rule is implemented as originally promulgated, oil and gas production on the properties in which we hold oil and gas interests could be adversely affected to the extent the rules and any of their requirements impose increased operating costs on the oil and gas industry.

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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 have forced 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. Following a legal challenge, the EPA formally proposed the Affordable Clean Energy ("ACE") Rule, which replaced the CPP Rule. The ACE Rule went into effect on September 6, 2019 and was also subject to a legal challenge. 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.” Most recently, in May 2024, the EPA finalized a rule that repeals the ACE rule and establishes GHG standards and guidelines that require coal fired power plants to (1) convert to natural gas co-firing by January 1, 2030 and then retire by 2039, (2) install by 2032 carbon capture and sequestration technology capable of capturing 90% of all CO2 emissions, or (3) cease operations by 2032. The May 2024 rule has been challenged in the U.S. Circuit Court of Appeals, but the U.S. Supreme Court denied the challengers’ request to stay implementation of the rule pending the outcome of the litigation. The EPA recently filed a motion to hold the case in abeyance while the EPA reviews the May 2024 rule. However, we cannot predict what action the new administration may take with respect to the May 2024 rule. Notwithstanding the previous litigation, the CPP and the ACE led to premature retirements, and the new rule could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal. Congress has not yet adopted legislation to restrict carbon dioxide emissions from existing power plants and has not otherwise expanded the legal authority of the EPA following West Virginia v. EPA, but we cannot predict whether such legislation will be passed in the future or what the potential impacts of such legislation would be.

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. Following a legal challenge, the EPA undertook a review of the October 2015 rule, and, 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. In May 2024, the EPA issued a final NSPS rule for GHG emissions from new and reconstructed fossil fuel-fired combustion turbines, which notably, formally withdrew the December 2018 proposed amendments to the NSPS for GHG emissions from coal-fired EGUs, However, the EPA noted it was still  continuing to review the October 2015 rule.

Certain authorizations required for certain mining and oil and gas operations may be difficult to obtain or use due to challenges from environmental advocacy groups to the environmental analyses conducted by federal agencies before granting permits.  In particular, those approvals necessary for certain coal activities that are subject to the requirements of the National Environmental Policy Act (“NEPA”) are subject to real uncertainty. In April 2022, the Council on Environmental Quality (“CEQ”) issued a final rule, which is considered “Phase I” of the Biden Administration’s two-phased approach to modifying the NEPA, revoking some of the modifications made to the NEPA regulations under the previous administration and reincorporating the consideration of direct, indirect, and cumulative effects of major federal actions, including GHG emissions. In May 2024, the CEQ finalized the “Phase 2” updates, the “Bipartisan Permitting Reform Implementation Rule,” which revised the implementing regulations of the procedural provisions of NEPA and implemented the amendments to NEPA included in the June 3, 2023, Fiscal Responsibility Act of 2023. The final rule was challenged by various states and the litigation remains ongoing. More recently, in November 2024, the U.S. Court of Appeals for the D.C. Circuit held that the CEQ lacks authority to issue NEPA regulations. As a result of this ruling and the recent change in the U.S. presidential administration and the following executive orders, there is significant uncertainty with respect to current and future requirements for these analyses.

In November 2014, President Obama also announced an emission reduction agreement with China’s President Xi Jinping. 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. In December 2023, the United Arab Emirates hosted the 28th session of the Conference of the Parties ("COP28") where parties signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly and equitable manner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. Subsequent Conferences have sought to build on the Paris Agreement by calling for various to phase out fossil fuels and subsidies related to the same, though none have been legally binding. The full impact of these actions is uncertain at this time, though these international agreements have the potential to result in increased pressure from financial institutions and other stakeholders to eliminate or reduce fossil fuel use and GHG emissions related to the same. Additionally, the new administration has re-withdrawn the United States from the Paris Agreement, and may make changes to the United States’ participation in any of these programs, though the nature and timing of such changes are uncertain.

Moreover, many states, regions, and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities, either as part of cap and trade, carbon tax, or climate “superfund” laws. For example, in December 2024, New York adopted a law requiring companies that emitted over 1 billion tons of GHG emissions into the atmosphere between 2000 and 2018, with sufficient connections to the state, to pay into a “climate superfund”  to support climate-related adaptation and mitigation projects. Other states have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, and the outcome of any legal challenges, the demand for coal and oil and gas could be negatively impacted, which would have an adverse effect on our operations. Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities. For example, the RGGI calls for the implementation of a cap-and-trade program aimed at reducing carbon dioxide emissions from power plants in participating states. The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program. Similar to RGGI, five western states launched the Western Regional Climate Initiative, although only California, Washington and Quebec are currently active participants. We cannot predict what other regional greenhouse gas reduction initiatives may arise in the future.

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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.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by Surface Mining Control and Reclamation Act (“SMCRA”) permits are by statute exempted from RCRA permitting. Similarly, most wastes associated with the exploration, development, and production of oil & gas are exempt from regulation as hazardous wastes under RCRA, though these wastes typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require such wastes to become subject to more stringent storage, handling, treatment, or disposal requirements, which could impose significant additional costs on the operators of the properties in which we own coal or oil and gas interests. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

RCRA impacts the coal industry in particular because it regulates the disposal of certain CCB. On April 17, 2015, the EPA finalized regulations under RCRA for the disposal of CCB. Under the finalized regulations, CCB is regulated as “non-hazardous” waste and avoids the stricter, more costly, regulations under RCRA’s “hazardous” waste rules. While the classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our lessees’ operating costs and potentially reduce their ability to sell coal. The CCB rule was subject to legal challenge and ultimately remanded to the EPA. On August 28, 2020, the EPA published a final revised rule mandating the closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site-specific circumstances. Certain provisions of the revised CCB rule were vacated by the D.C. Circuit in 2018. Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCB facilities that sought approval to continue disposal of CCB and non-CCB waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule. While the EPA issued one conditional approval, the EPA required the remaining facilities to cease receipt of waste within 135 days of completion of public comment, or around July 2022. And, in January 2023, the EPA issued six proposed determinations to deny facilities’ requests to continue disposal into unlined surface impoundments. The current determinations, future determinations of the same nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. Most recently, in May 2024, the EPA finalized changes to the CCB regulations for inactive surface impoundments at inactive electric utilities in response to the D.C. Circuit’s 2018 decision. The final rule expands the scope of impoundments subject to regulation and established groundwater monitoring, corrective action, closure, and post closure care requirements for all CCB management units. Although the rule has been challenged by industry groups, the U.S. Supreme Court rejected the challengers’ request to stay the rule so the rule remains effective as promulgated. The combined effect of the CCB rules and the ELG regulations (discussed below) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for coal.

On November 3, 2015, the EPA published the final rule ELG, revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technological improvements in the steam electric power industry over the last three decades. The EPA has from time to time updated the applicable ELG regulations and most recently, in May 2024, finalized a new ELG rule applicable to steam electric power generating facilities that sets new discharge limits for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate, and legacy wastewaters. Although it is uncertain what actions the new administration may take regarding the 2024 ELG rule, to the extent the 2024 rule, which applies to a major portion of the electric power industry, remains in effect, it may impact the market for products in which we own a mineral interest.

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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. Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. Rulemakings to establish the extent of such jurisdiction were finalized in 2015 and 2020, respectively, and both rulemakings were subject to substantial litigation. Although the EPA and Corps of Engineers did not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico vacated the 2020 rule in decisions announced during the third quarter of 2021. In January 2023, the EPA and Corps of Engineers published a final revised definition of WOTUS founded upon a pre-2015 definition, including updates to incorporate existing Supreme Court decisions. Following legal challenge to the January 2023 rule and the Supreme Court’s decision in Sackett v. EPA, the EPA issued a revised WOTUS rule in September 2023. Due to the injunction in certain states, however, the implementation of the September 2023 rule currently varies by state. The new Administration may seek to take additional action with respect to these regulations, although the substance and timing of such action cannot be predicted. 

States issue a certificate pursuant to Clean Water Act Section 401 that is required for the Corps of Engineers to issue a Section 404 permit. In October 2021, the U.S. District Court for the Northern District of California vacated a 2020 rule revising the Section 401 certification process. The Supreme Court stayed this vacatur and, in September 2023, the EPA finalized its Clean Water Act Section 401 Water Quality Certification Improvement Rule, effective as of November 27, 2023. The Water Quality Certification Improvement Rule was challenged by various states and a coalition of industry groups and the challenge remains ongoing. While the full extent and impact of these actions is unclear at this time due to the litigation and the new U.S. presidential administration, any disruption in the ability to obtain required permits may result in increased costs and project delays. 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.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (“USFWS”) works closely with state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related and oil and gas exploration and production activities. In recent years, there has been uncertainty with respect to ESA regulation. For example, in October 2021, the Biden Administration proposed the rollback of new rules promulgated under the first Trump Administration and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while establishing a process to regulate or permit exceptions to such a prohibition. Additionally, in June 2022, the USFWS and the National Marine Fisheries Service (“NMFS”) published a final rule rescinding the 2020 regulatory definition of “habitat.” Most recently, in April 2024, the USFWS and NMFS finalized three rules that revise regulations for classifying species and designating critical habitat, interagency cooperation, and protecting endangered and threatened species. Among other things, these rules reinstate prior language affirming that listing determinations are made “without reference to possible economic or other impacts of such determination,” clarify the standards for delisting species, revise the set of circumstances for when critical habitat may be not prudent, revise the criteria for identifying unoccupied critical habitat, and reinstate the general application of the “blanket rule” option for protecting newly listed threatened species. We cannot predict what actions the new administration may take with respect to these regulations and the timing with respect to the same. As a result, there is significant uncertainty with respect to ESA regulation at this time. If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered or to redesignate a species from threatened to endangered, we or the operators of the properties in which we hold oil and gas or mineral interests could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.

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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.

MSHA has also published, and may continue to publish, requests for information on various mining topics that may result in additional rules applicable to our operations and the operations of our lessees. Recent requests include topics such as engineering controls and best practices to lower miners’ exposure to respirable coal mine dust and exposure of underground miners to diesel exhaust. Recent MSHA rulemaking actions include, for example:

● In April 2024, MSHA adopted a rule on respirable crystalline silica, most commonly found in the mining environment through quartz. The final rule, which took effect on June 17, 2024, amends the existing MSHA standards to lower the permissible exposure limit of respirable crystalline silica, as well as set forth new or revised standards for exposure sampling, corrective actions, medical surveillance for metal and non-metal miners, and respiratory protection requirements.

● In December 2024, MSHA adopted a rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments. The final rule, effective January 9, 2025, adopts various voluntary consensus standards to promote innovation in mine safety and health technologies.

● In December 2023, MSHA published a final rule, which took effect on January 19, 2024, requiring that mine operators and independent contractors operating mobile equipment develop, implement, and periodically update a written safety program for surface mobile equipment (excluding belt conveyors) at surface mines and surface areas of underground mines. The deadline for compliance with the rule was July 17, 2024.

MSHA has also finalized a number of rules related to controlling exposure to coal mine dust, which has resulted in progressively stricter exposure limits imposed by MHSA regulations. These requirements impose a number of dust monitoring obligation and mine ventilation requirements on our coal lessees’ operations. Compliance with these rules can result in increased costs on our lessees’ operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations. It is uncertain whether any of the above or other various proposed rules or requests for information would have material impacts on our operations, our costs of operation, or the operations of our lessees.

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.

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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. The majority of our lessees have obtained or applied for permits to mine a significant portion of its coal that is currently planned to be mined over the next five years, and continue to be 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, 2024, affiliates of our general partner employed 54 people who directly supported our operations. None of these employees were subject to a collective bargaining agreement.

Human Capital 

We believe all individuals are entitled to courtesy, dignity, and respect, and we support a culture of integrity and personal and professional growth. We are strong leaders within our community, and we seek to uphold a positive presence in all areas where we live and work.

Website Access to Partnership Reports

Our internet address is www.nrplp.com. We make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on 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 a website at www.sec.gov that contains reports, proxy and information statements and other information filed by us.

Corporate Governance Matters

Our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy and our Corporate Governance Guidelines adopted by the Board of Directors, as well as the charter for our Audit Committee and Compensation, Nominating and Governance 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.

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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, 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. 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, 2024, we and our subsidiaries had approximately $142.3 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. 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 $14 million due thereunder during 2025. 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.

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Global pandemics have in the past and may continue to adversely affect our business.

The COVID-19 pandemic adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. 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 another global pandemic.

Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material 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;

• 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, 2024, we recorded impairment charges of approximately $0.1 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.

Changes to trade regulations, including trade restrictions, sanctions, tariffs, or duties, could significantly harm our results of operations.

Restrictions on international trade, such as sanctions, tariffs, duties and other governmental controls on imports or exports of goods, could adversely affect our business. In February 2025, the U.S. presidential administration imposed new tariffs on China and China responded with tariffs on select U.S. goods, including coal, which could negatively affect the price of coal. If new legislation or additional trade restrictions are adopted or geopolitical tensions were to increase and reduce the price received by our lessees for coal sales, the amount of royalties that we receive from our lessees would also be reduced which could adversely affect our free cash flow.

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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 worldwide and regional economic and political conditions impacting supply and demand. In addition, the impact of the Sisecam Chemicals 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 28% of our total revenues in 2024. We also own significant interests in all of Foresight’s mining operations, which accounted for approximately 16% of our total revenues in 2024. We also own a significant interest in Alabama Kanu's Oak Grove operation, which accounted for approximately 12% of our total revenues in 2024. 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.

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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. Further, in October 2023, the Federal Reserve, Office of the Comptroller of the Currency and the Federal Deposit Insurance Corp. released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change. Although, the future of these principles is uncertain in the new U.S. presidential administration. 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. Any laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may increase compliance costs, and result in potential restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions. Additionally, the SEC released its final rule on climate-related disclosures on March 6, 2024, requiring the disclosure of certain climate-related risks and financial impacts, as well as greenhouse gas emissions. Under the rule, large accelerated filers would be required to incorporate the applicable climate-related disclosures into their filings beginning in fiscal year 2025, with additional requirements relating to the disclosure of Scope 1 and 2 greenhouse gas emissions, if material, and attestation reports for certain large accelerated filers subsequently phasing in. However, the future of the SEC climate rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges; moreover, it is uncertain whether the Commission may seek to change or revoke the rule though we cannot predict whether such action will occur or its timing. As a result, the ultimate impact of the SEC rule, or any similar climate-related disclosure requirements imposed in the future, on our business is uncertain and may result in increased compliance costs and increased costs of and restrictions on 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.

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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. Thus, any changes in environmental laws and regulations or reinterpretations of enforcement policies, or in presidential administrations, that result in more stringent or costly obligations could adversely affect our performance.

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, or changes in presidential administrations, 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. 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.”

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. Sisecam Chemicals USA Inc., a wholly owned subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş, appoints four of the seven Board of Managers of Sisecam Wyoming and we appoint three. Any changes to the distribution policy or the capital expenditure plans approved by the 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.

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Sisecam Wyoming's reserve and resource data are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future, which could materially and adversely affect the quantities and value of Sisecam Wyoming's reserves and resources.

Sisecam Wyoming's reserve and resource estimates may vary substantially from the actual amounts of minerals Sisecam Wyoming is able to recover economically from their reserves. There are numerous uncertainties inherent in estimating quantities of reserves and resources, including many factors beyond Sisecam Wyoming's control. Estimates of reserves and resources necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to, among other aspects:

• future prices of soda ash, mining and production costs, capital expenditures and transportation costs;

• future mining technology and processes;

• the effects of regulation by governmental agencies; and

• geologic and mining conditions, which may not be identified by available exploration data and may differ from Sisecam Wyoming's experiences in areas where it currently mines.

Please read Items 1 and 2. “Business and Properties—Trona Resources and Trona Reserves” for more information including pertinent additional assumptions regarding Sisecam Wyoming's reserve estimates in this Report. Actual production, revenue and expenditures with respect to Sisecam Wyoming's reserves will likely vary from their estimates, and these variations may be material.

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, 2024, 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.

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Risks Related to Our Structure

Unitholders may not be able to remove our general partner even if they wish to do so.

Our managing general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the Board of Directors on an annual or any other basis.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner 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). Because of their substantial ownership in us, the removal of our general partner would be difficult without the consent of our general partner and its affiliates.

In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwise change our management:

• generally, if a person acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and

• 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.

We may issue additional common units or other equity securities without common unitholder approval, which could 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 without common unitholder approval (subject to applicable NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

• an existing unitholder’s proportionate ownership interest in NRP will decrease;

• the amount of cash available for distribution on each unit may decrease;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.

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.

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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.

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  managing 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. 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.

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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. Further, while unitholders of publicly traded partnerships are, subject to certain limitations, entitled to a deduction equal to 20% of their allocable share of a publicly traded partnership’s “qualified business income,” this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. 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.

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.

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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, 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.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible, our general partner may elect to either pay the taxes (including any applicable 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.

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.

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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 from their distributions and sale proceeds 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, 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.

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 all aspects 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.

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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 Risk Factors

Our business is subject to cybersecurity risks.

Our business is increasingly dependent on our information and operational technologies and services, and those of our service providers. Threats to information and operational 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.

In addition, the frequency and magnitude of cyber-attacks is increasing and attackers have become more sophisticated. Cyber-attacks are similarly evolving and include, without limitation, use of malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and loss or corruption of data. We may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognized until deployed. We may also be unable to investigate or remediate incidents as attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.

We cannot ensure that our insurance coverage will be sufficient to cover all the losses or expenses we may experience as a result of such cyber-attacks. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent cyber-attacks or other incidents from occurring. If a cyber-attack was to occur, it could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations, misdirected wire transfers, an inability to settle transactions or maintain operations, disruptions in operations, or other adverse events. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses, loss of business or potential liability, including regulatory enforcement, violation of privacy or securities laws and regulations, and individual or class action claims. Any cyber incident could have a material adverse effect on our business, financial condition and results of operations.

36

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cybersecurity Risk Management and Strategy

We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information.

Our cyber risk management program is integrated into our overall risk management system, which includes a cybersecurity risk assessment process, that routinely evaluates potential impacts of cybersecurity risks on our business, including our operations, financial stability, and reputation. These assessments inform our cybersecurity risk mitigation strategies. The results are regularly shared with management and the Audit Committee as part of their involvement in managing and overseeing cybersecurity risks.

Key aspects of our cybersecurity risk management program include:

• risk assessments designed to help identify material cybersecurity risks to our critical systems and information;

• a security team principally responsible for managing (1) our cybersecurity risk assessment processes, (2) our security controls, and (3) our response to cybersecurity incidents;

• the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security controls;

• cybersecurity awareness training for our employees, incident response personnel, and management; and

• a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents.

We have established separate processes and procedures to oversee and identify cybersecurity risks associated with our use of third-party service providers. All third parties involved in our cybersecurity risk assessments and risk management are required to provide reports designed to allow us to monitor and assess such third parties’ security controls.

As of the date of this report, though the Partnership and our service providers have experienced certain cybersecurity incidents, we have not identified any risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected or are reasonably likely to materially affect us, including our operations, business strategy, results of operations, or financial condition. Despite implementation of our cybersecurity process, we face ongoing risks from certain cybersecurity threats that, if realized, are reasonably likely to materially affect us, including our operations, business strategy, results of operations, or financial condition. See "Item 1A. Risk Factors – Our business is subject to cybersecurity risks" included elsewhere in this Annual Report on Form 10-K.

Cybersecurity Governance

Our Board of Directors considers cybersecurity risk as part of its risk oversight function and has delegated to its Audit Committee oversight of cybersecurity and other information technology risks. Our Audit Committee oversees management’s implementation of our cybersecurity risk management program.

Our Audit Committee receives periodic reports from management on our cybersecurity risks. In addition, management updates our Audit Committee, as necessary, regarding significant cybersecurity incidents. Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity. Our Board of Directors also receives, as necessary, briefings from management on our cybersecurity risk management program and receive presentations on cybersecurity topics from IT leadership, which includes our Chief Sustainability and Administrative Officer ("CSAO"), or external experts as part of the Board’s continuing education on topics that impact public companies.

Our cybersecurity team, led by the CSAO, is responsible for coordinating and executing on the cybersecurity response procedures and for seeking assistance from other Partnership stakeholders and external advisors. Our cybersecurity team includes the CSAO and IT leadership. The team has primary responsibility for our overall cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our cybersecurity team includes professionals with deep cybersecurity expertise across multiple industries. The CSAO has over 20 years of audit, risk management and cybersecurity experience covering the energy, pipeline, utilities, manufacturing, and financial services industries.Our management team stays informed about and monitors efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, which may include briefings from internal information technology personnel, threat intelligence and other information obtained from public or private sources, including external consultants engaged by us, and alerts and reports produced by security tools deployed in the IT environment.

ITEM 3. LEGAL PROCEEDINGS

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings 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.

37

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 14, 2025, there were approximately 10,935 beneficial 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 present 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 consist of the following subjects:

• Executive Overview

• Results of Operations

• Liquidity and Capital Resources

• Inflation

• Environmental Regulation

• Related Party Transactions

• Summary of Critical Accounting Estimates

• Recent Accounting Standards

As used in this Item 7, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where 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. 

38

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) less equity earnings from unconsolidated investment, net 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.

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.

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. 

39

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, 2024 are as follows:

	Operating Segments					Corporate and
(In thousands)	Mineral Rights			Soda Ash		Financing			Total
Revenues and other income	$	249,872		$	18,135	$	—		$	268,007
Net income (loss)	$	206,403		$	17,964	$	(40,723	)	$	183,644
Adjusted EBITDA (1)	$	222,007		$	38,610	$	(25,151	)	$	235,466
Cash flow provided by (used in)
Operating activities	$	242,168		$	38,610	$	(32,285	)	$	248,493
Investing activities	$	7,511		$	—	$	—		$	7,511
Financing activities	$	(1,086	)	$	—	$	(236,463	)	$	(237,549	)
Distributable cash flow (1)	$	249,679		$	38,610	$	(32,285	)	$	256,004
Free cash flow (1)	$	244,833		$	38,610	$	(32,285	)	$	251,158

(1) See"—Results of Operations" below for reconciliations to the most comparable GAAP financial measures.

40

Current Results/Market Commentary

Business Outlook and Quarterly Distributions 

We generated $248.5 million of operating cash flow and $251.2 million of free cash flow during the year ended December 31, 2024, and ended the year with $116.7 million of liquidity consisting of $30.4 million of cash and cash equivalents and $86.3 million of borrowing capacity under our Opco Credit Facility. As of December 31, 2024 our leverage ratio was 0.6x.

In the first quarter of 2024, holders of our warrants to purchase common units (the "warrants") exercised a total of 1,219,665 warrants with a strike price of $34.00. We settled these warrants on a net basis with a total of $55.7 million in cash and 198,767 common units. In the second quarter of 2024, holders of our warrants exercised the remaining 320,335 warrants with a strike price of $34.00. We settled these warrants on a net basis with $10.0 million in cash and 89,059 common units. Following these transactions, of the originally issued 4.0 million warrants, after giving effect to these settlements and all prior settlements, no warrants remain outstanding.

In May 2024, we executed a negotiated transaction with holders of our Class A Preferred Units ("preferred units") pursuant to which we repurchased an aggregate of 40,000 preferred units for $40.0 million in cash. In September 2024, we redeemed the remaining 31,666 preferred units for $31.7 million in cash. Of the originally issued 250,000 preferred units, after giving effect to these redemptions and all prior redemptions, no preferred units remain outstanding.

In 2024, we exercised our option under the Opco Credit Facility to increase the total aggregate commitment under the Opco Credit Facility twice, initially by $30.0 million from $155.0 million to $185.0 million and subsequently by $15.0 million from $185.0 million to $200.0 million. These increases in the total aggregate commitment were made pursuant to an accordion feature of the Opco Credit Facility. In October 2024, we entered into the Seventh Amendment to the Opco Credit Facility which extended the maturity from August 2027 to October 2029. The Seventh Amendment also removed reference to the preferred units and warrants, which are no longer outstanding, and includes modifications to Opco's ability to declare and make certain restricted payments.

In February 2024, we paid a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2023 as well as a $2.15 million cash distribution on the preferred units with respect to the fourth quarter of 2023. We paid a special cash distribution of $2.44 per common unit of NRP in March 2024 to help cover unitholder tax liabilities associated with owning NRP's common units in 2023. In May 2024, we paid a cash distribution of $0.75 per common unit of NRP with respect to the first quarter of 2024 as well as a $2.15 million cash distribution on the preferred units with respect to the first quarter of 2024. In August 2024, we paid a cash distribution of $0.75 per common unit of NRP with respect to the second quarter of 2024 as well as a $0.95 million cash distribution on the preferred units with respect to the second quarter of 2024. In November 2024, we paid a cash distribution of $0.75 per common unit of NRP with respect to the third quarter of 2024.

In February 2025, the Board of Directors declared a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2024. Additionally, NRP has announced it will pay special cash distribution of $1.21 in March 2025 to help cover unitholder tax liabilities associated with owning NRP's common units in 2024. Future distributions on our common 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 of Directors determines is necessary for future operating and capital needs. 

Mineral Rights Business Segment 

Revenues and other income during the year ended December 31, 2024 decreased $46.7 million, or 16%, as compared to the prior year. Cash provided by operating activities and free cash flow during the year ended December 31, 2024 decreased $17.8 million and $17.6 million, respectively, compared to the prior year. These decreases were primarily due to lower metallurgical coal sales prices and lower thermal coal sales prices and volumes as compared to the prior year, partially offset by one-time carbon neutral revenues and cash flow in 2024.

Metallurgical and thermal coal prices remained weak throughout 2024, primarily due to muted steel demand impacting metallurgical coal and mild weather, high inventory levels, and low natural gas prices impacting thermal coal. While we do not expect significant changes in these factors or to pricing in 2025, metallurgical and thermal coal pricing is still higher compared to long-term historical norms. It appears a new price floor has resulted from input cost inflation as well as ongoing labor shortages and operators' limited access to capital. 

We continue to explore and identify carbon neutral revenue sources across our large portfolio of surface, mineral, and timber assets, including the sequestration of carbon dioxide in our underground pore space and standing forests, lithium production, and the generation of electricity using geothermal, solar, and wind energy. We were notified that the previously announced underground carbon sequestration lease agreement executed in 2022 would not be renewed for another lease term and has been terminated as per the lessee's rights in the agreement.  

Soda Ash Business Segment 

Revenues and other income during the year ended December 31, 2024 decreased $55.3 million, or 75%, as compared to the prior year primarily due to lower international soda ash sales prices due to increased global soda ash capacity and weaker global demand for new construction and automobiles.

Cash provided by operating activities and free cash flow during the year ended December 31, 2024 decreased $42.6 million as compared to the prior year as the decline in revenues and other income resulted in lower cash distributions received from Sisecam Wyoming during the year ended December 31, 2024. 

We expect soda ash prices to remain low for the foreseeable future as it will take several years for the market to absorb the influx of new global capacity. However, many producers are currently operating below cost of production as the market is experiencing its lowest sales prices in decades. As this challenging market persists, distributions from Sisecam Wyoming are expected to be below historical levels.

41

Results of Operations

Year Ended December 31, 2024 and 2023 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)	2024		2023		Decrease			Change
Mineral Rights	$	249,872	$	296,612	$	(46,740	)		(16	)%
Soda Ash		18,135		73,397		(55,262	)		(75	)%
Total	$	268,007	$	370,009	$	(102,002	)		(28	)%

The changes in revenues and other income are discussed for each of the operating segments below:

42

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)	2024			2023			(Decrease)			Change
Coal sales volumes (tons)
Appalachia
Northern		1,031			1,145			(114	)		(10	)%
Central		14,137			13,927			210			2	%
Southern		2,661			2,670			(9	)		(0	)%
Total Appalachia		17,829			17,742			87			0	%
Illinois Basin		5,723			8,119			(2,396	)		(30	)%
Northern Powder River Basin		2,826			4,589			(1,763	)		(38	)%
Gulf Coast		1,342			1,477			(135	)		(9	)%
Total coal sales volumes		27,720			31,927			(4,207	)		(13	)%
Coal royalty revenue per ton
Appalachia
Northern	$	3.25		$	7.15		$	(3.90	)		(55	)%
Central		7.13			8.95			(1.82	)		(20	)%
Southern		10.22			12.81			(2.59	)		(20	)%
Illinois Basin		2.26			3.61			(1.35	)		(37	)%
Northern Powder River Basin		4.87			4.50			0.37			8	%
Gulf Coast		0.80			0.66			0.14			21	%
Combined average coal royalty revenue per ton		5.74			6.83			(1.09	)		(16	)%
Coal royalty revenues
Appalachia
Northern	$	3,348		$	8,192		$	(4,844	)		(59	)%
Central		100,845			124,631			(23,786	)		(19	)%
Southern		27,185			34,205			(7,020	)		(21	)%
Total Appalachia		131,378			167,028			(35,650	)		(21	)%
Illinois Basin		12,927			29,350			(16,423	)		(56	)%
Northern Powder River Basin		13,768			20,666			(6,898	)		(33	)%
Gulf Coast		1,069			969			100			10	%
Unadjusted coal royalty revenues		159,142			218,013			(58,871	)		(27	)%
Coal royalty adjustment for minimum leases		(109	)		(2	)		(107	)		(5,350	)%
Total coal royalty revenues	$	159,033		$	218,011		$	(58,978	)		(27	)%
Other revenues
Production lease minimum revenues	$	4,365		$	3,322		$	1,043			31	%
Minimum lease straight-line revenues		16,530			19,389			(2,859	)		(15	)%
Carbon neutral revenues		15,703			2,969			12,734			429	%
Wheelage revenues		9,324			12,191			(2,867	)		(24	)%
Property tax revenues		7,100			6,219			881			14	%
Coal overriding royalty revenues		2,358			2,175			183			8	%
Lease amendment revenues		3,724			3,070			654			21	%
Aggregates royalty revenues		2,904			2,876			28			1	%
Oil and gas royalty revenues		8,566			7,387			1,179			16	%
Other revenues		4,542			1,124			3,418			304	%
Total other revenues	$	75,116		$	60,722		$	14,394			24	%
Royalty and other mineral rights	$	234,149		$	278,733		$	(44,584	)		(16	)%
Transportation and processing services revenues		10,878			14,923			(4,045	)		(27	)%
Gain on asset sales and disposals		4,845			2,956			1,889			64	%
Total Mineral Rights segment revenues and other income	$	249,872		$	296,612		$	(46,740	)		(16	)%

43

Coal Royalty Revenues

Approximately 75% of coal royalty revenues and approximately 55% of coal royalty sales volumes were derived from metallurgical coal during the year ended December 31, 2024. Total coal royalty revenues decreased $59.0 million from 2023 to 2024. The discussion by region is as follows:  

• Appalachia: Coal royalty revenues decreased $35.7 million primarily due to decreased metallurgical coal sales prices during the year ended December 31, 2024, as compared to the prior year.

• Illinois Basin: Coal royalty revenues decreased $16.4 million primarily due to lower thermal coal sales volumes and prices as compared to the prior year.

• Northern Powder River Basin: Coal royalty revenues decreased $6.9 million primarily due to decreased sales volumes during the year ended December 31, 2024, as compared to the prior year. The decrease in sales volumes was due to our lessee mining less on our property during 2024 as compared to 2023 in accordance with its mine plan.

Other Revenues

Other revenues increased $14.4 million during the year ended December 31, 2024 as compared to the prior year primarily driven by carbon neutral revenues received from a third party related to its creation of California Air Resources Board carbon offset credits from our properties.

Transportation and Processing Services Revenues

Transportation and processing services revenues decreased $4.0 million during the year ended December 31, 2024 as compared to the prior year primarily due to a temporary relocation of certain production off of NRP's coal reserves. The fee per ton associated with the transportation and processing of the non-NRP coal is less than the fee per ton associated with the transportation and processing of NRP coal.

Soda Ash

Revenues and other income related to our Soda Ash segment decreased $55.3 million compared to the prior year primarily due to lower international soda ash sales prices due to increased global soda ash capacity and weaker global demand for new construction and automobiles.

Operating Expenses

The following table presents the significant categories of our consolidated operating expenses:

	For the Year Ended December 31,							Percentage
(In thousands)	2024		2023		Decrease			Change
Operating expenses
Operating and maintenance expenses	$	28,036	$	32,315	$	(4,279	)		(13	)%
Depreciation, depletion and amortization		15,535		18,489		(2,954	)		(16	)%
General and administrative expenses		25,151		26,111		(960	)		(4	)%
Asset impairments		87		556		(469	)		(84	)%
Total operating expenses	$	68,809	$	77,471	$	(8,662	)		(11	)%

Total operating expenses decreased $8.7 million primarily due to a $4.3 million decrease in operating and maintenance expenses during the year ended December 31, 2024 and a $3.0 million decrease in depreciation, depletion and amortization compared to the prior year. The decrease in operating and maintenance expenses was primarily due to lower overriding royalty expense from an agreement with WPPLP during the year ended December 31, 2024 as compared to the year ended December 31, 2023. This overriding royalty expense is fully offset by coal royalty revenue we receive from this property. This decrease in operating and maintenance expense was partially offset by higher bad debt expense during the year ended December 31, 2024 as compared to the prior year. The decrease in depreciation, depletion and amortization was primarily due to lower coal production from certain Illinois Basin and Northern Powder River Basin properties during the year ended December 31, 2024 as compared to the prior year.

Interest Expense, Net

Interest expense, net increased $1.5 million primarily due to higher borrowings outstanding on the Opco Credit Facility during the year ended December 31, 2024 as compared to the year ended December 31, 2023.

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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, 2024
Net income (loss)	$	206,403	$	17,964		$	(40,723	)	$	183,644
Less: equity earnings from unconsolidated investment		—		(18,135	)		—			(18,135	)
Add: total distributions from unconsolidated investment		—		38,781			—			38,781
Add: interest expense, net		—		—			15,554			15,554
Add: depreciation, depletion and amortization		15,517		—			18			15,535
Add: asset impairments		87		—			—			87
Adjusted EBITDA	$	222,007	$	38,610		$	(25,151	)	$	235,466
December 31, 2023
Net income (loss)	$	245,527	$	73,140		$	(40,232	)	$	278,435
Less: equity earnings from unconsolidated investment		—		(73,397	)		—			(73,397	)
Add: total distributions from unconsolidated investment		—		81,478			—			81,478
Add: interest expense, net		—		—			14,103			14,103
Add: depreciation, depletion and amortization		18,471		—			18			18,489
Add: asset impairments		556		—			—			556
Adjusted EBITDA	$	264,554	$	81,221		$	(26,111	)	$	319,664

Net income decreased $94.8 million as compared to the prior year primarily due to the decrease in revenues and other income as discussed above. Adjusted EBITDA decreased $84.2 million as compared to the prior year primarily due to a $42.5 million decrease in Adjusted EBITDA within our Mineral Rights segment as a result of lower revenues and other income during the year ended December 31, 2024 as discussed above and a $42.6 million decrease in Adjusted EBITDA within our Soda Ash segment primarily due to lower distributions received from Sisecam Wyoming during the year ended December 31, 2024.

Distributable Cash Flow ("DCF") and Free Cash Flow ("FCF") (Non-GAAP Financial Measures)

The following table presents the three major categories of the statement of cash flows by business segment:

	Operating Segments					Corporate and
For the Year Ended (In thousands)	Mineral Rights			Soda Ash		Financing			Total
December 31, 2024
Cash flow provided by (used in)
Operating activities	$	242,168		$	38,610	$	(32,285	)	$	248,493
Investing activities		7,511			—		—			7,511
Financing activities		(1,086	)		—		(236,463	)		(237,549	)
December 31, 2023
Cash flow provided by (used in)
Operating activities	$	259,983		$	81,207	$	(30,212	)	$	310,978
Investing activities		5,426			—		(10	)		5,416
Financing activities		(583	)		—		(342,913	)		(343,496	)

45

The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCF and FCF:

	Operating Segments					Corporate and
For the Year Ended (In thousands)	Mineral Rights			Soda Ash		Financing			Total
December 31, 2024
Net cash provided by (used in) operating activities	$	242,168		$	38,610	$	(32,285	)	$	248,493
Add: proceeds from asset sales and disposals		4,846			—		—			4,846
Add: return of long-term contract receivable		2,665			—		—			2,665
Distributable cash flow	$	249,679		$	38,610	$	(32,285	)	$	256,004
Less: proceeds from asset sales and disposals		(4,846	)		—		—			(4,846	)
Free cash flow	$	244,833		$	38,610	$	(32,285	)	$	251,158
December 31, 2023
Net cash provided by (used in) operating activities	$	259,983		$	81,207	$	(30,212	)	$	310,978
Add: proceeds from asset sales and disposals		2,963			—		—			2,963
Add: return of long-term contract receivable		2,463			—		—			2,463
Less: maintenance capital expenditures		—			—		(10	)		(10	)
Distributable cash flow	$	265,409		$	81,207	$	(30,222	)	$	316,394
Less: proceeds from asset sales and disposals		(2,963	)		—		—			(2,963	)
Free cash flow	$	262,446		$	81,207	$	(30,222	)	$	313,431

Cash provided by operating activities, DCF and FCF decreased $62.5 million, $60.4 million and $62.3 million, respectively from 2023 to 2024. The discussion by segment is as follows:

• Mineral Rights Segment: Cash provided by operating activities, DCF and FCF decreased $17.8 million, $15.7 million and $17.6 million, respectively, primarily due to lower metallurgical coal sales prices and lower thermal coal sales prices and volumes during 2024 as compared to the prior year, partially offset by cash received from one-time carbon neutral revenues in 2024. 

• Soda Ash Segment: Cash provided by operating activities, DCF and FCF decreased $42.6 million primarily due to lower distributions received from Sisecam Wyoming in 2024 as compared to 2023. 

• Corporate and Financing Segment: Cash used in operating activities increased $2.1 million primarily due to higher cash paid for interest resulting from higher borrowings outstanding on the Opco Credit Facility during the year ended December 31, 2024. 

For discussion of our Results of Operations comparing 2023 to 2022, refer to our 2023 Annual Report on Form 10-K filed March 7, 2024 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

46

Liquidity and Capital Resources

Current Liquidity

As of December 31, 2024, we had total liquidity of $116.7 million, consisting of $30.4 million of cash and cash equivalents and $86.3 million in borrowing capacity under our Opco Credit Facility. We have debt service obligations, including approximately $14 million of principal repayments on Opco’s senior notes in 2025. As of December 31, 2024 our leverage ratio was 0.6x. The following table calculates our leverage ratio:

(In thousands)	For the Year Ended December 31, 2024
Adjusted EBITDA	$	235,466
Debt—at December 31, 2024	$	142,347
Leverage Ratio	0.6x

Cash Flows

Year Ended December 31, 2024 and 2023 Compared

Cash flows provided by operating activities decreased $62.5 million, from $311.0 million during the year ended December 31, 2023 to $248.5 million during the year ended December 31, 2024 primarily due to decreased cash flow within our Mineral Rights and Soda Ash segments, all discussed above.

Cash flows used in financing activities decreased $105.9 million, from $343.5 million used during the year ended December 31, 2023 to $237.5 million used during the year ended December 31, 2024 primarily due to the following:

• $106.7 million of decreased cash used for the redemption of preferred units in 2024 as compared to 2023;

• $81.4 million of decreased debt repayments in 2024 as compared to 2023; and

• $15.7 million decreased distributions to preferred unitholders in 2024 as compared to 2023.

These decreases in cash flow used were partially offset by the following:

• $81.0 million of decreased borrowings on the Opco Credit Facility in 2024 as compared to 2023;

• $9.6 million of increased cash used for the warrant settlements in 2024 as compared to 2023;

• $4.9 million of increased cash used for other items, net in 2024 as compared to 2023; and

• $2.2 million of increased distributions to common unitholders and the general partner in 2024 as compared to 2023.

For discussion of our Cash Flows comparing 2023 to 2022, refer to our 2023 Annual Report on Form 10-K filed March 7, 2024 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

47

Capital Resources and Obligations

Debt, Net

We had the following debt outstanding as of December 31, 2024 and 2023:

	December 31,
(In thousands)	2024		2023
Current portion of long-term debt, net	$	14,192	$	30,785
Long-term debt, net		127,876		124,273
Total debt, net	$	142,068	$	155,058

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, 2024:

	Payments Due by Period
Debt Obligations (In thousands)	Total		2025		2026		2027		2028		2029		Thereafter
Opco:
Debt principal payments (including current maturities) (1)	$	142,347	$	14,332	$	14,331	$	—	$	—	$	113,684	$	—
Debt interest payments (2)		2,175		1,450		725		—		—		—		—
Total	$	144,522	$	15,782	$	15,056	$	—	$	—	$	113,684	$	—

⁽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

Despite rising costs beginning in 2021 and continuing into 2024, inflation did not have a material impact on operations for the years ended December 31, 2024, 2023 and 2022.

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.

48

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.

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.

Recently Adopted Accounting Standards

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2023-07—Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures ("ASU 2023-07"). The amendments in ASU 2023-07 improve reportable segment disclosure requirements, primarily through enhanced disclosures about segment expenses. The adoption of ASU 2023-07 with our 2024 Form 10-K did not have a material impact on our Consolidated Financial Statements. See "Item 8. Financial Statements and Supplementary Data—Note 7. Segment Information" for more information. 

Recent Accounting Standards

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures ("ASU 2024-03"). ASU 2024-03 is intended to improve disclosures about a public business entity's expenses and provide more detailed information to investors about the types of expenses in commonly presented expense captions. The guidance is effective for annual periods beginning after December 15, 2026 and quarterly periods beginning after December 31, 2027 and can be adopted prospectively to financial statements issued for reporting periods after the effective date or retrospectively to all prior periods presented in the financial statements. We are currently evaluating the potential impact of this guidance on our disclosures.

49

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:

Commodity Price Risk

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices. Historically, coal prices have been volatile, with prices fluctuating widely, and are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenues and could potentially trigger an impairment of our coal properties or a violation of certain financial debt covenants. Because substantially all our reserves are coal, changes in coal prices have a more significant impact on our financial results. 

We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees' failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees' operations and adversely affect our future financial results. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices. 

The market price of soda ash and energy costs directly affects the profitability of Sisecam Wyoming's operations. If the market price for soda ash declines, Sisecam Wyoming's sales revenues will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile and are likely to remain volatile in the future. 

The following table shows the fluctuations of our commodity prices over the past three years: 

	2024		2023		2022
Combined average coal royalty revenue per ton	$	5.74	$	6.83	$	6.90
Soda ash average sales price per short ton	$	235.60	$	284.97	$	270.42

Interest Rate Risk

Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to variable interest rates based upon SOFR. At December 30, 2024, we had $113.7 million in borrowings outstanding under the Opco Credit Facility. If interest rates were to increase by 1%, annual interest expense would increase approximately $1.1 million,assuming the same principal amount remained outstanding during the year.

Fair Value of Financial Assets and Liabilities

Our financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. We use available market data and valuation methodologies to estimate the fair value of our debt and contract receivable.

The following table shows the carrying value and estimated fair value of our debt and contract receivable:

			December 31,
			2024				2023
			Carrying		Estimated		Carrying		Estimated
(In thousands)	Fair Value Hierarchy Level		Value		Fair Value		Value		Fair Value
Debt:
Opco Senior Notes (1)		3	$	28,384	$	27,498	$	59,224	$	56,533
Opco Credit Facility (2)		3		113,684		113,684		95,834		95,384
Assets:
Contract receivable, net (current and long-term) (3)		3	$	26,321	$	22,776	$	28,946	$	24,492

⁽¹⁾ The fair value of the Opco Senior Notes was estimated by management utilizing the present value replacement method incorporating the interest rate of the Opco Credit Facility.

⁽²⁾ The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.

⁽³⁾ The fair value of the Partnership's contract receivable was determined based on the present value of future cash flow projections related to the underlying asset at a discount rate of 15% at December 31, 2024 and 2023.

50

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)	52
Report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm  (PCAOB ID 238)	54
Report of BDO USA, P.C. Independent Registered Public Accounting Firm  (PCAOB ID 243)	55
Consolidated Balance Sheets as of December 31, 2024 and 2023	56
Consolidated Statements of Comprehensive Income for the years ended December 31, 2024, 2023 and 2022	57
Consolidated Statements of Partners’ Capital for the years ended December 31, 2024, 2023 and 2022	58
Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022	59
Notes to Consolidated Financial Statements	60

51

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, 2024 and 2023, the related consolidated statements of comprehensive income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the reports of PricewaterhouseCoopers LLP and BDO USA, P.C., the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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 $257 million and $277 million as of December 31, 2024 and 2023, respectively, and the Partnership’s equity in earnings of Sisecam Wyoming is stated at $18 million in 2024, $73 million in 2023 and $60 million in 2022. Those statements were audited by PricewaterhouseCoopers LLP for the year ended December 31, 2024 and BDO USA, P.C. for the years ended December 31, 2023 and 2022 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 PricewaterhouseCoopers LLP and BDO USA, P.C.

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, 2024, 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 February 28, 2025 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 PricewaterhouseCoopers LLC and the reports of BDO USA P.C. 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.

52

Impairment Assessment of Mineral Rights

Description of the Matter

At December 31, 2024, the Partnership’s mineral rights, net totaled $380 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 asset’s net book value may not be recoverable. Management evaluates various qualitative and quantitative factors in determining whether or not events or changes in circumstances indicate that the net book value 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 indicator assessment involved our subjective judgment because, in determining whether an impairment indicator 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 indicators of impairment pertaining to mineral rights and the related subjective judgments.   To test the Partnership’s mineral rights impairment assessment, our audit procedures included, among others, making inquiries of management (including personnel in operations) to understand changes in business, and evaluating the subjective judgments used in the Partnership’s assessment. Specifically, we corroborated reserve information to new reserve studies when available. Additionally, we inspected lease modifications of royalty-based lease contracts. We searched for and evaluated other publicly available information pertaining to certain of their lessees, that corroborates or contradicts management’s assessment.

/s/    Ernst & Young LLP

We have served as the Partnership’s auditor since 2002.

Houston, Texas

February 28, 2025

53

Report of Independent Registered Public Accounting Firm

To the Board of Managers and Members of Sisecam Wyoming LLC

Opinion on the Financial Statements

We have audited the accompanying balance sheet of Sisecam Wyoming LLC (the “Company”) as of December 31, 2024, and the related statements of operations and comprehensive income, of members' equity and of cash flows for the year then ended, including 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 as of December 31, 2024, 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 of these financial statements 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 Matters

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 (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters 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.

Revenue Recognition – Sales to Others

As described in Note 2 to the financial statements, the Company’s sales to others was $578 million for the year ended December 31, 2024. The Company’s revenues are recognized at a point-in-time when control of goods transfers to the customer. The time at which delivery and transfer of title, and therefore control, occurs ranges from the point in time when the product leaves the Company’s facilities to agreed upon delivery points. Agreed upon delivery points at which control of the product transfers includes points where product reaches the port of loading, a vessel, or other agreed location, thereby rendering the performance obligation fulfilled.  Management recognizes revenue as the amount of consideration expected to be received in exchange for transferring promised goods to customers.

The principal consideration for our determination that performing procedures relating to revenue recognition for sales to others is a critical audit matter is a high degree of auditor effort in performing procedures related to the Company’s revenue recognition for sales to others.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included, among others, (i) testing revenue recognized for a sample of revenue transactions by obtaining and inspecting source documents such as customer contracts, purchase orders, invoices, proof of shipment or delivery, and subsequent cash receipts; and (ii) confirming a sample of outstanding customer invoice balances as of December 31, 2024 and, for confirmations not returned, obtaining and inspecting source documents, such as customer contracts, purchase orders, invoices, proof of shipment or delivery, and subsequent cash receipts.

/s/PricewaterhouseCoopers LLP

Charlotte, North Carolina

February 28, 2025

We have served as the Company's auditor since 2024.

54

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, 2023, the related statements of operations and comprehensive income, members’ equity, and cash flows for the years ended December 31, 2023 and 2022, 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, 2023, and the results of its operations and its cash flows for the years ended December 31, 2023 and 2022, 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/ BDO USA, P.C.

We served as the Company's auditor from 2022 to 2024.

Charlotte, North Carolina

March 7, 2024

55

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

	December 31,
(In thousands, except unit data)	2024			2023
ASSETS
Current assets
Cash and cash equivalents	$	30,444		$	11,989
Accounts receivable, net		31,469			41,086
Other current assets, net		1,961			2,218
Total current assets	$	63,874		$	55,293
Land		24,008			24,008
Mineral rights, net		379,638			394,483
Intangible assets, net		12,924			13,682
Equity in unconsolidated investment		257,355			276,549
Long-term contract receivable, net		23,480			26,321
Other long-term assets, net		11,628			7,540
Total assets	$	772,907		$	797,876
LIABILITIES AND CAPITAL
Current liabilities
Accounts payable	$	909		$	885
Accrued liabilities		12,121			12,987
Accrued interest		302			584
Current portion of deferred revenue		4,341			4,599
Current portion of long-term debt, net		14,192			30,785
Total current liabilities	$	31,865		$	49,840
Deferred revenue		55,814			38,356
Long-term debt, net		127,876			124,273
Other non-current liabilities		6,244			7,172
Total liabilities	$	221,799		$	219,641
Commitments and contingencies (see Note 15)
Class A Convertible Preferred Units (71,666 units issued and outstanding at December 31, 2023 at $1,000 par value per unit) (See Note 4)	$	—		$	47,181
Partners’ capital
Common unitholders’ interest (13,049,123 and 12,634,642 units issued and outstanding at December 31, 2024 and 2023, respectively)	$	543,231		$	503,076
General partner’s interest		9,547			8,005
Warrant holders’ interest		—			23,095
Accumulated other comprehensive loss		(1,670	)		(3,122	)
Total partners' capital	$	551,108		$	531,054
Total liabilities and partners' capital	$	772,907		$	797,876

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

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 

	For the Year Ended December 31,
(In thousands, except per unit data)	2024			2023			2022
Revenues and other income
Royalty and other mineral rights	$	234,149		$	278,733		$	307,013
Transportation and processing services		10,878			14,923			21,072
Equity in earnings of Sisecam Wyoming		18,135			73,397			59,795
Gain on asset sales and disposals		4,845			2,956			1,082
Total revenues and other income	$	268,007		$	370,009		$	388,962
Operating expenses
Operating and maintenance expenses	$	28,036		$	32,315		$	34,903
Depreciation, depletion and amortization		15,535			18,489			22,519
General and administrative expenses		25,151			26,111			21,852
Asset impairments		87			556			4,457
Total operating expenses	$	68,809		$	77,471		$	83,731
Income from operations	$	199,198		$	292,538		$	305,231
Other expenses, net
Interest expense, net	$	(15,554	)	$	(14,103	)	$	(26,274	)
Loss on extinguishment of debt		—			—			(10,465	)
Total other expenses, net	$	(15,554	)	$	(14,103	)	$	(36,739	)
Net income	$	183,644		$	278,435		$	268,492
Less: income attributable to preferred unitholders		(4,248	)		(16,719	)		(30,000	)
Less: redemption of preferred units		(24,485	)		(60,929	)		—
Net income attributable to common unitholders and the general partner	$	154,911		$	200,787		$	238,492
Net income attributable to common unitholders	$	151,813		$	196,771		$	233,722
Net income attributable to the general partner		3,098			4,016			4,770
Net income per common unit (see Note 6)
Basic	$	11.69		$	15.59		$	18.72
Diluted		11.35			13.08			13.39
Net income	$	183,644		$	278,435		$	268,492
Comprehensive income (loss) from unconsolidated investment and other		1,452			(21,839	)		15,506
Comprehensive income	$	185,096		$	256,596		$	283,998

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

57

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

												Accumulated
												Other			Total
	Common Unitholders					General			Warrant			Comprehensive			Partners'
(In thousands)	Units		Amounts			Partner			Holders			Income (Loss)			Capital
Balance at December 31, 2021		12,351	$	203,062		$	1,787		$	47,964		$	3,211		$	256,024
Net income (1)		—		263,122			5,370			—			—			268,492
Distributions to common unitholders and the general partner		—		(33,697	)		(687	)		—			—			(34,384	)
Distributions to preferred unitholders		—		(29,653	)		(605	)		—			—			(30,258	)
Issuance of unit-based awards		155		—			—			—			—			—
Unit-based awards amortization and vesting, net		—		1,965			—			—			—			1,965
Capital contribution		—		—			112			—			—			112
Comprehensive income from unconsolidated investment and other		—		—			—			—			15,506			15,506
Balance at December 31, 2022		12,506	$	404,799		$	5,977		$	47,964		$	18,717		$	477,457
Net income (2)		—		272,866			5,569			—			—			278,435
Redemptions of preferred units		—		(59,710	)		(1,219	)		—			—			(60,929	)
Distributions to common unitholders and the general partner		—		(68,510	)		(1,398	)		—			—			(69,908	)
Distributions to preferred unitholders		—		(21,628	)		(441	)		—			—			(22,069	)
Issuance of unit-based awards		129		—			—			—			—			—
Unit-based awards amortization and vesting, net		—		5,854			—			—			—			5,854
Capital contribution		—		—			142			—			—			142
Warrant settlements		—		(30,595	)		(625	)		(24,869	)		—			(56,089	)
Comprehensive loss from unconsolidated investment and other		—		—			—			—			(21,839	)		(21,839	)
Balance at December 31, 2023		12,635	$	503,076		$	8,005		$	23,095		$	(3,122	)	$	531,054
Net income (3)		—		179,971			3,673			—			—			183,644
Redemptions of preferred units		—		(23,995	)		(490	)		—			—			(24,485	)
Distributions to common unitholders and the general partner		—		(70,703	)		(1,443	)		—			—			(72,146	)
Distributions to preferred unitholders		—		(6,270	)		(128	)		—			—			(6,398	)
Issuance of unit-based awards		126		—			—			—			—			—
Unit-based awards amortization and vesting, net		—		2,894			—			—			—			2,894
Capital contribution		—		—			782			—			—			782
Warrant settlements		288		(41,742	)		(852	)		(23,095	)		—			(65,689	)
Comprehensive income from unconsolidated investment and other		—		—			—			—			1,452			1,452
Balance at December 31, 2024		13,049	$	543,231		$	9,547		$	—		$	(1,670	)	$	551,108

(1)	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.
(2)	Net income includes $16.7 million of income attributable to preferred unitholders that accumulated during the period, of which $16.4 million is allocated to the common unitholders and $0.3 million is allocated to the general partner.
(3)	Net income includes $4.2 million of income attributable to preferred unitholders that accumulated during the period, of which $4.2 million is allocated to the common unitholders and $0.1 million is allocated to the general partner.

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

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
(In thousands)	2024			2023			2022
Cash flows from operating activities
Net income	$	183,644		$	278,435		$	268,492
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		15,535			18,489			22,519
Distributions from unconsolidated investment		38,781			81,478			44,835
Equity earnings from unconsolidated investment		(18,135	)		(73,397	)		(59,795	)
Gain on asset sales and disposals		(4,845	)		(2,956	)		(1,082	)
Loss on extinguishment of debt		—			—			10,465
Asset impairments		87			556			4,457
Bad debt expense		4,185			2,244			1,062
Unit-based compensation expense		11,309			10,910			5,773
Amortization of debt issuance costs and other		(1,509	)		1,303			2,410
Change in operating assets and liabilities:
Accounts receivable		7,285			(164	)		(18,671	)
Accounts payable		25			(1,108	)		37
Accrued liabilities		(2,088	)		(225	)		935
Accrued interest		(281	)		(406	)		(224	)
Deferred revenue		17,200			(3,483	)		(15,424	)
Other items, net		(2,700	)		(698	)		1,049
Net cash provided by operating activities	$	248,493		$	310,978		$	266,838
Cash flows from investing activities
Proceeds from asset sales and disposals	$	4,846		$	2,963		$	1,083
Return of long-term contract receivable		2,665			2,463			1,723
Capital expenditures		—			(10	)		(118	)
Net cash provided by investing activities	$	7,511		$	5,416		$	2,688
Cash flows from financing activities
Debt borrowings	$	167,850		$	248,834		$	70,000
Debt repayments		(181,028	)		(262,396	)		(339,396	)
Distributions to common unitholders and the general partner		(72,146	)		(69,908	)		(34,384	)
Distributions to preferred unitholders		(6,398	)		(22,069	)		(30,258	)
Redemptions of preferred units		(71,666	)		(178,334	)		—
Redemption of preferred units paid-in-kind		—			—			(19,321	)
Warrant settlements (See Note 4)		(65,689	)		(56,089	)		—
Other items, net		(8,472	)		(3,534	)		(12,596	)
Net cash used in financing activities	$	(237,549	)	$	(343,496	)	$	(365,955	)
Net increase (decrease) in cash and cash equivalents	$	18,455		$	(27,102	)	$	(96,429	)
Cash and cash equivalents at beginning of period		11,989			39,091			135,520
Cash and cash equivalents at end of period	$	30,444		$	11,989		$	39,091
Supplemental cash flow information:
Cash paid for interest	$	15,452		$	13,856		$	25,265

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

59

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization and Nature of Operations

Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP" or "general partner"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC ("managing general partner"), a 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 indirectly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. All members of the Board of Directors are appointed by RCM.

2.    Summary of Significant Accounting Policies

Basis of Presentation

The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in 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, 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 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.

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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, 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 $4.7 million and $5.4 million at December 31, 2024 and 2023, respectively. The total allowance related to short-term notes receivables included in other current assets, net on the Partnership's Consolidated Balance Sheets was $0.0 million and $0.3 million at December 31, 2024 and 2023, 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 $0.8 million and $0.9 million at December 31, 2024 and 2023, respectively. The Partnership recorded bad debt expense of $4.2 million, $2.2 million and $1.1 million included in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income for the year ended December 31, 2024, 2023 and 2022, 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, 2024 were $8.9 million of accrued employee costs and $3.2 million of accrued property taxes. These amounts were $10.3 million and $2.7 million of accrued employee costs and accrued property taxes, respectively, at December 31, 2023.

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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 revenues. Revenues related to consideration for carbon neutral activities 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.

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 Accounting Standards Codification 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 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 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 coal royalty revenues from its production leases over the next twelve months, the Partnership is unable to estimate the current portion of deferred revenue.

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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. 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.

Unit-Based Compensation

The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units. The Partnership's service and performance-based awards are valued using the closing price of NRP's units as of the grant date while the Partnership's market-based awards are valued using a Monte Carlo simulation. Compensation cost is 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. 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 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.

Recently Adopted Accounting Standard

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2023-07—Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures ("ASU 2023-07"). The amendments in ASU 2023-07 improve reportable segment disclosure requirements, primarily through enhanced disclosures about segment expenses. The adoption of ASU 2023-07 with NRP's 2024 Form 10-K did not have a material impact on the Partnership's Consolidated Financial Statements. See Note 7. Segment Information for more information.

Recently Issued Accounting Standard

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures ("ASU 2024-03"). ASU 2024-03 is intended to improve disclosures about a public business entity's expenses and provide more detailed information to investors about the types of expenses in commonly presented expense captions. The guidance is effective for annual periods beginning after December 15, 2026 and quarterly periods beginning after December 31, 2027 and can be adopted prospectively to financial statements issued for reporting periods after the effective date or retrospectively to all prior periods presented in the financial statements. NRP is currently evaluating the potential impact of this guidance on its Consolidated Financial Statements.

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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 from contracts with customers by major source:

	For the Year Ended December 31,
(In thousands)	2024		2023		2022
Coal royalty revenues	$	159,033	$	218,011	$	226,956
Production lease minimum revenues		4,365		3,322		5,854
Minimum lease straight-line revenues		16,530		19,389		18,792
Carbon neutral revenues (1)		15,703		2,969		8,600
Property tax revenues		7,100		6,219		5,878
Wheelage revenues		9,324		12,191		13,961
Coal overriding royalty revenues		2,358		2,175		3,434
Lease amendment revenues		3,724		3,070		3,201
Aggregates royalty revenues		2,904		2,876		3,299
Oil and gas royalty revenues		8,566		7,387		16,161
Other revenues		2,744		1,124		877
Royalty and other mineral rights revenues	$	232,351	$	278,733	$	307,013
Transportation and processing services revenues		8,597		12,411		17,876
Total Mineral Rights segment revenues from contracts with customers	$	240,948	$	291,144	$	324,889

⁽¹⁾ During 2024, NRP recorded revenues of approximately $13.4 million from a third party related to its creation of California Air Resources Board carbon offset credits from our properties. $11.3 million of this revenue was recorded in the three months ended December 31, 2024.

The following table details the Partnership's Mineral Rights segment contract assets and liabilities resulting from contracts with customers:

	December 31,
(In thousands)	2024		2023
Receivables
Accounts receivable, net	$	27,358	$	37,206
Other current assets, net (1)		—		429
Other long-term assets, net (2)		2,352		—
Contract liabilities
Accounts payable (3)	$	125	$	—
Current portion of deferred revenue		4,341		4,599
Deferred revenue		55,814		38,356

⁽¹⁾ Other current assets, net includes short-term notes receivables from contracts with customers.

(2)	Other long-term assets, net includes amounts prepaid by NRP related to override agreements from contracts with customers as well as other long-term assets due from contracts with customers.
(3)	Accounts payable includes override payments owed by NRP from contracts with customers.

The following table shows the activity related to the Partnership's Mineral Rights segment deferred revenue resulting from contracts with customers:

	For the Year Ended December 31,
(In thousands)	2024			2023			2022
Balance at beginning of period (current and non-current)	$	42,955		$	46,437		$	61,862
Increase due to minimums and lease amendment fees		32,960			17,526			19,073
Recognition of previously deferred revenue		(15,760	)		(21,008	)		(34,498	)
Balance at end of period (current and non-current)	$	60,155		$	42,955		$	46,437

The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty contracts with customers are as follows as of December 31, 2024 (in thousands): 

Lease Term (1)	Weighted Average Remaining Years		Annual Minimum Payments
0 - 5 years		2.3	$	13,478
5 - 10 years		5.4		17,477
10+ years		11.2		26,309
Total		7.3	$	57,264

⁽¹⁾ Lease term does not include renewal periods.

64

 

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 entitled 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 have paid in additional preferred units (such additional preferred units, the "PIK units"). The preferred units had a perpetual term, unless converted or redeemed. However, in 2024 all remaining preferred units were redeemed and none of the Partnership's preferred units remain outstanding.

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 were exercisable by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the warrants, NRP may have, at its option, elected to settle the warrants in common units or cash, each on a net basis. However, in 2024 all remaining warrants were settled and none of the Partnership's warrants remain outstanding.

Accounting for the Preferred Units and Warrants

Classification

The preferred units were accounted for as temporary equity on NRP's Consolidated Balance Sheets due to certain contingent redemption rights that may have been exercised at the election of preferred purchasers. The warrants were 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

Preferred Units

During the year ended December 31, 2024, the Partnership redeemed a total of 71,666 preferred units for $71.7 million in cash. During the year ended December 31, 2023, the Partnership redeemed a total of 178,334 preferred unit for $178.3 million in cash. Of the originally issued 250,000 preferred units, no preferred units remained outstanding as of December 31, 2024. and 71,666 preferred units remained outstanding as of December 31, 2023. The preferred units had a $47.2 million carrying value included in class A convertible preferred units on the Partnership's Consolidated Balance Sheets at  December 31, 2023.

Activity related to the preferred units is as follows:

	Units			Financial
(In thousands, except unit data)	Outstanding			Position
Balance at December 31, 2021		269,321		$	183,908
Redemption of preferred units paid-in-kind		(19,321	)		(19,321	)
Balance at December 31, 2022		250,000		$	164,587
Redemption of preferred units		(178,334	)		(117,406	)
Balance at December 31, 2023		71,666		$	47,181
Redemption of preferred units		(71,666	)		(47,181	)
Balance at December 31, 2024		—		$	—

65

 

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Warrants

During the year ended December 31, 2024, the Partnership settled a total of 1,540,000 warrants to purchase common units with a strike price of $34.00. On  January 29, 2024 (the  "January 2024 exercise date"), holders of the Partnership's warrants exercised 462,165 warrants at a strike price of $34.00. The Partnership settled the warrants on a net basis with $10.0 million in cash and 198,767 common units. The 15-day VWAP ending on the business day prior to the  January 2024 exercise date was $97.62. On  February 7, 2024 (the  "February 7, 2024 exercise date"), holders of the Partnership's warrants exercised 128,750 warrants at a strike price of $34.00. The Partnership settled the warrants on a net basis with $8.0 million in cash. The 15-day VWAP ending on the business day prior to the  February 7, 2024 exercise date was $96.29. On  February 8, 2024 (the  "February 8, 2024 exercise date"), holders of the Partnership's warrants exercised 128,750 warrants at a strike price of $34.00. The 15-day VWAP ending on the business day prior to the  February 8, 2024 exercise date was $95.63. The Partnership settled these warrants on a net basis with $7.9 million in cash. On  February 14, 2024 (the  "February 14, 2024 exercise date"), holders of the Partnership's warrants exercised 500,000 warrants at a strike price of $34.00. The 15-day VWAP ending on the business day prior to the  February 14, 2024 exercise date was $93.47. The Partnership settled these warrants on a net basis with $29.7 million in cash. In April 2024 (the "April 2024 exercise date"), holders of the Partnership's warrants exercised 320,335 warrants at a strike price of $34.00. The Partnership settled the warrants on a net basis with $10.0 million in cash and 89,059 common units. The 15-day VWAP ending on the business day prior to the April 2024 exercise date was $90.33.

 In 2023, the Partnership negotiated transactions with holders of the Partnership's warrants pursuant to which the Partnership repurchased and retired an aggregate of 752,500 warrants with a strike price of $22.81 and 710,000 warrants with a strike price of $34.00 for approximately $56.1 million in cash. As of December 31, 2024, zero warrants remained outstanding. 

Of the originally issued 4,000,000 warrants, no warrants remain outstanding as of December 31, 2024 and 1,540,000 warrants to purchase common units with a strike price of $34.00 were outstanding as of  December 31, 2023. These warrants had a carrying value of $23.1 million included in warrant holders' interest within partners' capital on the Partnership's Consolidated Balance Sheets at December 31, 2023. 

Activity related to the warrants is as follows:

	Warrants			Financial
(In thousands, except warrant data)	Outstanding			Position
Balance at December 31, 2021 and 2022		3,002,500		$	47,964
Warrant settlement		(1,462,500	)		(24,869	)
Balance at December 31, 2023		1,540,000		$	23,095
Warrant settlements		(1,540,000	)		(23,095	)
Balance at December 31, 2024		—		$	—

Embedded Features

Certain embedded features within the preferred unit and warrant purchase agreement were accounted for at fair value and were remeasured each quarter. See Note 12. Fair Value Measurements for further information regarding valuation of these embedded derivatives.

66

 

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

5. Common and Preferred Unit Distributions

The Partnership makes cash distributions to common unitholders and made cash distributions to 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 available to common unitholders and the general partner is reduced by preferred unit distributions that accumulated during the period. NRP reduced net income available to common unitholders and the general partner by $4.2 million, $16.7 million and $30.0 million during the year ended December 31, 2024, 2023 and 2022, respectively, as a result of accumulated preferred unit distributions earned during the period. Income available to common unitholders and the general partner is also reduced by the difference between the fair value of the consideration paid upon redemption and the carrying value of the preferred units. As such, NRP reduced net income available to common unitholders and the general partner by $24.5 million and $60.9 million during the year ended December 31, 2024 and 2023, respectively.

The following table shows the cash distributions declared and paid to common and preferred unitholders during the year ended December 31, 2024, 2023 and 2022, respectively:

		Common Units				Preferred Units
				Total				Total
		Distribution		Distribution (1)		Distribution		Distribution
Month Paid	Period Covered by Distribution	per Unit		(In thousands)		per Unit		(In thousands)
2024
February	October 1 - December 31, 2023	$	0.75	$	9,918	$	30.00	$	2,150
March (2)	Special Distribution		2.44		32,268		—		—
May	January 1 - March 31, 2024		0.75		9,987		30.00		2,150
May (3)	April 1 - May 8, 2024		—		—		12.33		493
August	April 1 - June 30, 2024		0.75		9,986		30.00		950
September (4)	July 1 - September 3, 2024		—		—		20.68		655
November	July 1 - September 30, 2024		0.75		9,987		—		—
2023
February	October 1 - December 31, 2022	$	0.75	$	9,571	$	30.00	$	7,500
February (5)	January 1 - February 8, 2023		—		—		12.33		586
March (6)	Special Distribution		2.43		31,329		—		—
May	January 1 - March 31, 2023		0.75		9,669		30.00		6,075
May (7)	April 1 - May 5, 2023		—		—		11.33		406
June (8)	April 1 - June 2, 2023		—		—		20.33		915
August	April 1 - June 30, 2023		0.75		9,669		30.00		3,650
August (9)	June 30 - August 8, 2023		—		—		12.33		432
September (10)	June 30 - September 12, 2023		—		—		23.67		355
November	July 1 - September 30, 2023		0.75		9,670		30.00		2,150
2022
February	October 1 - December 31, 2021	$	0.45	$	5,672	$	30.00	$	7,500
February (11)	January 1 - February 8, 2022		—		—		13.35		258
May	January 1 - March 31, 2022		0.75		9,570		30.00		7,500
August	April 1 - June 30, 2022		0.75		9,571		30.00		7,500
November	July 1 - September 30, 2022		0.75		9,571		30.00		7,500

(1)	Totals include the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest.
(2)	Special distribution was made to help cover unitholder tax liabilities associated with owning NRP common units during 2023.
(3)	Relates to accrued distribution paid upon the redemption of 40,000 preferred units in May 2024
(4)	Relates to accrued distribution paid upon the redemption of 31,666 preferred units in September 2024.
(5)	Relates to accrued distribution paid upon the redemption of 47,499 preferred units in February 2023.
(6)	Special distribution was made to help cover unitholder tax liabilities associated with owning NRP's common units during 2022.
(7)	Relates to accrued distribution paid upon the redemption of 35,834 preferred units in May 2023.
(8)	Relates to accrued distribution paid upon the redemption of 45,000 preferred units in June 2023.
(9)	Relates to accrued distribution paid upon the redemption of 35,000 preferred units in August 2023.
(10)	Relates to accrued distribution paid upon the redemption of 15,001 preferred units in September 2023.
(11)	Relates to accrued distribution paid upon the redemption of 19,321 preferred units paid-in-kind in February 2022.

67

 

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

6. Net Income Per Common Unit

Basic net income per common unit is computed by dividing net income, after considering income attributable to preferred unitholders, the difference between the fair value of the consideration paid upon redemption and the carrying value of the preferred units, and the general partner’s general partner interest, by the weighted average number of common units outstanding. Diluted net income 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 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, 2024, 2023 and 2022 includes the assumed conversion of the preferred units that remained outstanding during the respective period. The calculation of diluted net income per common unit for the year ended December 31, 2024 and 2023 does not include the assumed conversion of preferred units that were redeemed during the period, as the inclusion of these units would be 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, 2024, 2023 and 2022 includes the net settlement of the warrants for the period during which they were outstanding.

The following table reconciles the numerators and denominators of the basic and diluted net income per common unit computations and calculates basic and diluted net income per common unit:

	For the Year Ended December 31,
(In thousands, except per unit data)	2024			2023			2022
Basic net income per common unit
Net income attributable to common unitholders	$	151,813		$	196,771		$	233,722
Weighted average common units—basic		12,991			12,619			12,484
Basic net income per common unit	$	11.69		$	15.59		$	18.72
Diluted net income per common unit
Weighted average common units—basic		12,991			12,619			12,484
Plus: dilutive effect of preferred units		281			2,059			6,176
Plus: dilutive effect of warrants		139			1,202			783
Plus: dilutive effect of unvested unit-based awards		236			216			210
Weighted average common units—diluted		13,647			16,096			19,653
Net income	$	183,644		$	278,435		$	268,492
Less: income attributable to preferred unitholders		(1,148	)		(2,694	)		—
Less: redemption of preferred units		(24,485	)		(60,929	)		—
Diluted net income attributable to common unitholders and the general partner	$	158,011		$	214,812		$	268,492
Less: diluted net income attributable to the general partner		(3,160	)		(4,296	)		(5,370	)
Diluted net income attributable to common unitholders	$	154,851		$	210,516		$	263,122
Diluted net income per common unit	$	11.35		$	13.08		$	13.39

68

 

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.

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.

NRP’s Chief Operating Decision Makers (“CODM”) are its Chief Executive Officer and President and Chief Operating Officer. Together, they evaluate the Partnership’s performance monthly through a review of the segments’ net income and free cash flow as compared to budget and utilize this information to assess the segments’ performance and allocate resources. NRP does not conduct operations on any of its assets or directly engage in any type of industrial activity. Instead, it leases its mineral and other rights to companies that conduct operations on its properties in exchange for paying royalties and other fees to the Partnership. Operating expenses, capital costs and other liabilities arising out of production activities are borne entirely by NRP's lessees. In the case of its soda ash investment, operations are managed by NRP's partner, Sisecam Chemicals Wyoming LLC. As such, none of the Partnership's expenses are considered to affect the trends reflected in the segments or consolidated information nor are they considered important to NRP’s future profitability. Accordingly, NRP has determined its significant segment expenses to be its employee related expenses, including compensation (salaries, benefits and bonus) and long-term incentive compensation as well as interest expense and property tax expense. The Partnership is responsible for paying property taxes on the properties it owns. Typically, NRP's lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties and this reimbursement amount is included within the Mineral Rights segment revenues. Reclassifications have been made to prior year amounts to conform with current year presentation. 

69

 

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2024
Revenues	$	245,027	$	—	$	—		$	245,027
Equity in earnings of Sisecam Wyoming		—		18,135		—			18,135
Gain on asset sales and disposals		4,845		—		—			4,845
Total revenues and other income	$	249,872	$	18,135	$	—		$	268,007
Less:									—
Compensation (salaries, benefits and bonus)	$	7,948	$	—	$	8,570		$	16,518
Long-term incentive compensation (1)		1,785		—		9,466			11,251
Property taxes		7,704		—		—			7,704
Depreciation, depletion and amortization		15,517		—		18			15,535
Asset impairments		87		—		—			87
Interest expense, net (2)		—		—		15,554			15,554
Other segment items (3)		10,428		171		7,115			17,714
Net income (loss)	$	206,403	$	17,964	$	(40,723	)	$	183,644
As of December 31, 2024
Total assets	$	509,127	$	257,355	$	6,425		$	772,907
For the Year Ended December 31, 2023
Revenues	$	293,656	$	—	$	—		$	293,656
Equity in earnings of Sisecam Wyoming		—		73,397		—			73,397
Gain on asset sales and disposals		2,956		—		—			2,956
Total revenues and other income	$	296,612	$	73,397	$	—		$	370,009
Less:
Compensation (salaries, benefits and bonus)	$	8,382	$	—	$	10,204		$	18,586
Long-term incentive compensation (4)		2,022		—		8,711			10,733
Property taxes		6,758		—		—			6,758
Depreciation, depletion and amortization		18,471		—		18			18,489
Asset impairments		556		—		—			556
Interest expense, net (2)		—		—		14,103			14,103
Other segment items (3)		14,896		257		7,196			22,349
Net income (loss)	$	245,527	$	73,140	$	(40,232	)	$	278,435
As of December 31, 2023
Total assets	$	516,844	$	276,549	$	4,483		$	797,876
For the Year Ended December 31, 2022
Revenues	$	328,085	$	—	$	—		$	328,085
Equity in earnings of Sisecam Wyoming		—		59,795		—			59,795
Gain on asset sales and disposals		1,082		—		—			1,082
Total revenues and other income	$	329,167	$	59,795	$	—		$	388,962
Less:
Compensation (salaries, benefits and bonus)	$	8,206	$	—	$	9,388		$	17,594
Long-term incentive compensation (5)		1,259		—		4,505			5,764
Property taxes		6,389		—		—			6,389
Depreciation, depletion and amortization		22,519		—		—			22,519
Asset impairments		4,457		—		—			4,457
Interest expense, net (2)		—		—		26,274			26,274
Loss on extinguishment of debt		—		—		10,465			10,465
Other segment items (3)		18,889		160		7,959			27,008
Net income (loss)	$	267,448	$	59,635	$	(58,591	)	$	268,492

⁽¹⁾ Long-term incentive compensation for the year ended December 31, 2024 includes (1) Mineral Rights segment: $1.4 million of equity compensation and $0.4 million of cash compensation; (2) Corporate & Financing segment: $9.1 million of equity compensation and $0.4 of cash compensation

(2)	Included in interest expense, net was $0.7 million, $0.3 million and $0.3 million of interest income for the years ended December 31, 2024, 2023 and 2022, respectively.
(3)	Other segment items in the Mineral Rights segment primarily include: insurance, legal, overriding royalty expense, processing and transportation expense, information technology, shared facility services, rent and professional fees. Other segment items in the Soda Ash segment primarily include professional fees. Other segment items in the Corporate and Financing segment primarily include: insurance, legal, information technology, shared facility services, rent and professional fees.
(4)	Long-term incentive compensation for the year ended December 31, 2023 includes (1) Mineral Rights segment: $1.4 million of equity compensation and $0.6 million of cash compensation; (2) Corporate & Financing segment: $8.4 million of equity compensation and $0.3 million of cash compensation
(5)	Long-term incentive compensation for the year ended December 31, 2022 includes (1) Mineral Rights segment: $0.8 million of equity compensation and $0.5 million of cash compensation; (2) Corporate & Financing segment: $4.1 million of equity compensation and $0.3 million of cash compensation

70

 

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)	2024			2023			2022
Balance at beginning of period	$	276,549		$	306,470		$	276,004
Income allocation to NRP’s equity interests (1)		22,800			78,179			64,712
Amortization of basis difference		(4,665	)		(4,783	)		(4,917	)
Other comprehensive income (loss)		1,452			(21,839	)		15,506
Distributions		(38,781	)		(81,478	)		(44,835	)
Balance at end of period	$	257,355		$	276,549		$	306,470

⁽¹⁾ Amounts reclassified into income out of accumulated other comprehensive loss was $6.0 million, $(17.9) million and $(6.8) million for the year ended December 31, 2024, 2023 and 2022, 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 $111.9 million and $116.6 million as of December 31, 2024 and 2023, 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, 2024, 2023 and 2022:

	For the Year Ended December 31,
(In thousands)	2024		2023		2022
Net sales	$	578,106	$	773,590	$	720,120
Gross profit		76,820		187,929		162,575
Net income		46,530		159,549		132,065

The financial position of Sisecam Wyoming is summarized as follows:

	December 31,
(In thousands)	2024		2023
Current assets	$	247,937	$	253,754
Noncurrent assets		277,471		284,131
Current liabilities		78,135		91,853
Noncurrent liabilities		150,428		119,533

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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,
	2024							2023
(In thousands)	Carrying Value		Accumulated Depletion			Net Book Value		Carrying Value		Accumulated Depletion			Net Book Value
Coal properties	$	660,961	$	(299,404	)	$	361,557	$	661,256	$	(285,470	)	$	375,786
Aggregates properties		8,655		(4,065	)		4,590		8,655		(3,761	)		4,894
Oil and gas royalty properties		12,354		(10,394	)		1,960		12,354		(10,082	)		2,272
Other		13,143		(1,612	)		11,531		13,143		(1,612	)		11,531
Total mineral rights, net	$	695,113	$	(315,475	)	$	379,638	$	695,408	$	(300,925	)	$	394,483

Depletion expense related to the Partnership’s mineral rights is included in depreciation, depletion and amortization on its Consolidated Statements of Comprehensive Income and totaled $14.8 million, $17.3 million and $20.9 million for the year ended December 31, 2024, 2023 and 2022, respectively. 

During the year ended December 31, 2024, the Partnership recorded a gain $4.8 million, included in gain on asset sales and disposals on the Consolidated Statements of Comprehensive Income primarily related to a coal property condemnation in the second quarter of 2024. During the years ended December 31, 2023 and 2022, the Partnership had $3.0 million and $1.1 million, respectively, included in gains on asset sales and disposals on the Consolidated Statements of Comprehensive Income.

Impairment of Mineral Rights

During the years ended December 31, 2024, 2023 and 2022, 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 as follows:

	For the Year Ended December 31,
(In thousands)	2024		2023		2022
Coal properties (1)	$	87	$	556	$	4,365
Aggregates properties		—		—		92
Total	$	87	$	556	$	4,457

⁽¹⁾ The Partnership recorded $0.1 million and $0.6 million of impairment expense during the year ended December 31, 2024 and 2023, respectively. 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%.     NRP compared the net book value of its mineral rights 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. The impairment recorded during the year ended December 31, 2022 was based on the estimated fair value of the assets versus its net book value and is a level 3 non-recurring fair value estimate. 

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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)	2024			2023
Intangible assets at cost	$	51,353		$	51,353
Less: accumulated amortization		(38,429	)		(37,671	)
Total intangible assets, net	$	12,924		$	13,682

Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of Comprehensive Income was $0.8 million, $1.0 million and $1.4 million for the year ended December 31, 2024, 2023 and 2022, respectively.

The estimates of amortization expense for the years ended December 31, as indicated below, are based on current lessee mining plans and are subject to revision as those plans change in future periods.

(In thousands)	Estimated Amortization Expense
2025	$	792
2026		691
2027		1,008
2028		720
2029		480

11.    Debt, Net

The Partnership's debt consists of the following:

	December 31,
(In thousands)	2024			2023
Opco Credit Facility	$	113,684		$	95,834
Opco Senior Notes
5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024	$	—		$	12,685
8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024		—			4,012
5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026		22,841			34,262
5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026		5,822			8,732
Total Opco Senior Notes	$	28,663		$	59,691
Total debt at face value	$	142,347		$	155,525
Net unamortized debt issuance costs		(279	)		(467	)
Total debt, net	$	142,068		$	155,058
Less: current portion of long-term debt		(14,192	)		(30,785	)
Total long-term debt, net	$	127,876		$	124,273

NRP LP Debt

2025 Senior Notes

In 2022, NRP redeemed all $300 million of its 9.125% senior notes due 2025 ("2025 Senior Notes"). Included in loss on extinguishment of debt on the Partnership's Consolidated Statements of Comprehensive Income for the year ended December 31, 2022, are $7.2 million of call premium and fees and the write off of $3.1 million of debt issuance costs related to the redemption of the 2025 Senior Notes. 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. 

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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, 2024 and 2023, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.

Opco Credit Facility

In May 2023, the Partnership entered into the Sixth Amendment (the "Sixth Amendment") to the Opco Credit Facility (the "Opco Credit Facility"). The Sixth Amendment extended the term of the Opco Credit Facility until August 2027. Lender commitments under the Opco Credit Facility increased from $130.0 million to $155.0 million, with the ability to expand such commitments to $200.0 million with the addition of future commitments. In February 2024, the Partnership exercised its option under the Opco Credit Facility to increase the total aggregate commitment under the Opco Credit Facility twice, initially by $30.0 million from $155.0 million to $185.0 million and subsequently by $15.0 million from $185.0 million to $200.0 million. These increases in the total aggregate commitment were made pursuant to an accordion feature of the Opco Credit Facility. In connection with the initial increase, a new lender joined the lending group with a commitment of $30.0 million. In October 2024, NRP entered into the Seventh Amendment to the Opco Credit Facility which extended the maturity from August 2027 to October 2029. The Seventh Amendment also removed reference to the preferred units and warrants, which are no longer outstanding, and includes modifications to Opco's ability to declare and make certain restricted payments.

Indebtedness under the Opco Credit Facility bears interest, at Opco's option, at:

• the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) SOFR plus 1%, in each case plus an applicable 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, 2023, the Partnership borrowed $248.8 million and repaid $223.0 million, resulting in $95.8 million in borrowings outstanding and $59.2 of available borrowing capacity under the Opco Credit Facility as of December 31, 2023. During the year ended December 31, 2024 the Partnership borrowed $167.9 million and repaid $150.0 million, resulting in $113.7 million in borrowings outstanding and $86.3 million of available borrowing capacity under the Opco Credit Facility as of December 31, 2024. The weighted average interest rate for the borrowings outstanding under the Opco Credit Facility for the year ended December 31, 2024 and 2023 was 8.77% and 8.70%, respectively. 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. As of December 31, 2024, this ratio was 0.6x; 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. As of December 31, 2024, this ratio was 14.7x.

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 of $302.8 million and $316.3 million classified as mineral rights, net and other long-term assets, net and $23.5 million and $26.3 million classified as long-term contract receivable, net on the Partnership’s Consolidated Balance Sheets as of December 31, 2024 and 2023, 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, including its long-term contract receivable as described in Note 17. Financing Transaction.

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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, 2024, only the 5.03% and 5.18% Opco Senior Notes, both due December 31, 2026, remain outstanding. These Opco Senior Notes have principal due annually in December and interest due semi-annually in June and December. As of December 31, 2024 and 2023, the Opco Senior Notes had cumulative principal balances of $28.7 million and $59.7 million, respectively. Opco made mandatory principal payments on the Opco Senior Notes of $31.0, $39.4 and $39.4 million during the year ended December 31, 2024, 2023 and 2022, 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 Opco 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.

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:

(In thousands)	Opco Senior Notes		Opco Credit Facility		Total
2025	$	14,332	$	—	$	14,332
2026		14,331		—		14,331
2027		—		—		—
2028		—		—		—
2029		—		113,684		113,684
Thereafter		—		—		—
	$	28,663	$	113,684	$	142,347

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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,
			2024				2023
			Carrying		Estimated		Carrying		Estimated
(In thousands)	Fair Value Hierarchy Level		Value		Fair Value		Value		Fair Value
Debt:
Opco Senior Notes (1)		3	$	28,384	$	27,498	$	59,224	$	56,533
Opco Credit Facility (2)		3		113,684		113,684		95,834		95,384
Assets:
Contract receivable, net (current and long-term) (3)		3	$	26,321	$	22,776	$	28,946	$	24,492

⁽¹⁾ The fair value of the Opco Senior Notes was estimated by management utilizing the present value replacement method incorporating the interest rate of the Opco Credit Facility.

⁽²⁾ The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.

⁽³⁾ The fair value of the Partnership's contract receivable was determined based on the present value of future cash flow projections related to the underlying asset at a discount rate of 15% at December 31, 2024 and 2023.

NRP had embedded derivatives in the preferred units related to certain conversion options, redemption features and the change of control provision that were 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 were based on numerous factors including the likelihood of the event occurring. The embedded derivatives were revalued quarterly and changes in their fair value would have been recorded in other expenses, net on the Partnership's Consolidated Statements of Comprehensive Income. The embedded derivatives had zero value as of December 31, 2023. As a result of the redemption of the Partnership's remaining preferred units in September 2024, NRP no longer has embedded derivatives associated with the preferred units as of December 31, 2024.

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.

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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. NRP also reimburses overhead costs incurred by its affiliates, and other related parties, 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.

Related party general and administrative expenses included on the Partnership's Consolidated Statement of Comprehensive Income are as follows:

	For the Year Ended December 31,
(In thousands)	2024		2023		2022
Operating and maintenance expenses	$	7,106	$	6,747	$	6,694
General and administrative expenses		5,420		5,408		4,864

The Partnership had accounts payable to related parties of $0.6 million on its Consolidated Balance Sheets at both December 31, 2024 and 2023. The Partnership had other current assets of $0.2 million and $0.1 million on its Consolidated Balance Sheets related to a related party prepaid expense at December 31, 2024 and 2023, respectively.

As a result of its office lease with WPPLP, the Partnership had a right-of-use asset and lease liability of $3.4 million and $3.5 million included in other long-term assets, net and other non-current liabilities, on its Consolidated Balance Sheets at December 31, 2024 and 2023, respectively.

During the years ended December 31, 2024, 2023 and 2022, the Partnership recognized $0.1 million, $5.1 million and $8.5 million in operating and maintenance expenses, respectively, on its Consolidated Statements of Comprehensive Income related to an overriding royalty agreement with WPPLP. At December 31, 2024 the Partnership had $0.5 million of other long-term assets, net on its Consolidated Balance Sheets related to a prepaid royalty for this agreement. This amount was zero for the year ended December 31, 2023.

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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,
	2024					2023					2022
(In thousands)	Revenues		Percent			Revenues		Percent			Revenues		Percent
Alpha Metallurgical Resources, Inc. (1)	$	67,714		28	%	$	86,118		23	%	$	102,352		26	%
Foresight (1)	$	39,178		16	%	$	60,495		16	%	$	65,597		17	%
Alabama Kanu Holdings, LLC (1) (2)	$	29,533		12	%	$	34,869		9	%	$	24,596		6	%

⁽¹⁾ Revenues from Alpha Metallurgical Resources, Inc., Foresight and Alabama Kanu Holdings, LLC are included within the Partnership's Mineral Rights segment.

⁽²⁾ Alabama Kanu Holdings, LLC purchased Hatfield Metallurgical Holdings, LLC in August 2024.

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, 2024. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

16.    Unit-Based Compensation

2017 Long-Term Incentive Plan

In December 2017, the Natural Resource Partners 2017 Long-Term Incentive Plan (the “2017 Plan”) was approved and it became effective in January 2018. The 2017 Plan 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 Plan is terminated by the Board of Directors or the committee appointed by the Board of Directors to administer the 2017 Plan, or the date all available common units available have been delivered. Common units delivered pursuant to the 2017 Plan 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 Plan. The 2017 Plan 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 Plan. The Partnership recognizes forfeitures for any awards issued under this plan as they occur.

Unit-Based Awards

Unit-based awards under the 2017 Plan 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.

During the years ended December 31, 2024 and 2023, the Partnership granted service, performance and market-based awards under its 2017 Plan and during the year ended December 31, 2022, the Partnership granted service-based awards. The Partnership's service and performance-based awards are valued using the closing price of NRP's common units as of the grant date while the Partnership's market-based awards are valued using a Monte Carlo simulation. The grant date fair value of the awards granted during the year ended December 31, 2024, 2023 and 2022 was $6.7 million, $16.0 million and $7.9 million, respectively. Included in these amounts is the grant-date fair value for the market-based awards valued using a Monte Carlo simulation of $2.5 million and $2.8 million for the year ended December 31, 2024 and 2023, respectively. Total unit-based compensation expense associated with these awards was $11.3 million, $10.9 million and $5.8 million for the year ended December 31, 2024, 2023 and 2022, respectively, and is included in general and administrative expenses and operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income. The unamortized cost associated with unvested outstanding awards as of December 31, 2024 was $9.5 million, which will be recognized over a weighted average period of 1.5 years. The unamortized cost associated with unvested outstanding awards as of December 31, 2023 was $13.3 million. The Partnership paid $6.4 million, $3.2 million and $2.9 million in cash during the year ended December 31, 2024, 2023 and 2022, respectively, for taxes on the unit-based award settlements during the respective years. These cash payments are included in other items, net under cash flows from financing activities on the Partnership's Consolidated Statements of Cash Flows. 

A summary of the unit activity in the outstanding grants during 2024 is as follows:

(In thousands)	Common Units			Weighted Average Grant Date Fair value per Common Unit
Outstanding grants at January 1, 2024		483		$	46.21
Granted		65		$	103.50
Fully vested and issued		(197	)	$	38.76
Forfeitures		(1	)	$	90.70
Outstanding at December 31, 2024		350		$	60.81

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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 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 the 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, 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, 2024 and 2023, NRP had the following current expected credit loss (“CECL”) allowance related to its receivables and long-term contract receivable:

	December 31,
	2024							2023
(In thousands)	Gross		CECL Allowance			Net		Gross		CECL Allowance			Net
Receivables	$	37,270	$	(4,425	)	$	32,845	$	47,170	$	(5,655	)	$	41,515
Long-term contract receivable		24,323		(843	)		23,480		27,265		(944	)		26,321
Total	$	61,593	$	(5,268	)	$	56,325	$	74,435	$	(6,599	)	$	67,836

NRP reversed $1.3 million and charged $1.1 million and $1.1 million in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income related to the change in the CECL allowance during the year ended December 31, 2024, 2023 and 2022, 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.

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

19.    Leases

As of December 31, 2024, the Partnership had two operating leases for office buildings. On January 1, 2019, the Partnership entered into a new lease for the West Virginia office building owned by WPPLP with a five-year base term and five additional five-year renewal options. Upon lease commencement and as of December 31, 2024 and 2023, the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liability on its Consolidated Balance Sheets using the present value of the future lease payments over 30 years. On January 1, 2023, the Partnership entered into a new lease for an office building in Houston with an 11.4 year initial term and two additional five-year renewal options. Upon lease commencement and as of December 31, 2024 and 2023, the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liability on its Consolidated Balance Sheets using the present value of the future lease payments over 21.4 years. The Partnership's right-of-use asset included within other long-term assets, net on its Consolidated Balance Sheets totaled $4.2 million and $4.3 million at December 31, 2024 and 2023, respectively. The Partnership's lease liability included in other non-current liabilities on its Consolidated Balance Sheets totaled $4.4 million and $4.3 million at December 31, 2024 and 2023, respectively. During the years ended December 31, 2024, 2023 and 2022, the Partnership incurred total operating lease expenses of $0.6 million, $0.6 million and $0.5 million included in both operating and maintenance expenses and general and administrative expenses on its Consolidated Statements of Comprehensive Income.

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, 2024
2025	$	601
2026		604
2027		607
2028		611
2029		614
After 2029		11,425
Total lease payments (1)	$	14,462
Less: present value adjustment (2)		(10,095	)
Total operating lease liability	$	4,367

⁽¹⁾ The remaining lease terms of the Partnership's two operating leases are 24 years and 19.4 years.

⁽²⁾ The present value of the operating lease liability on the Partnership's Consolidated Balance Sheets was calculated using a 13.5% discount rate on the 30-year lease and a 13.4% discount rate on the 21.4-year lease. These rates represent the Partnership's estimated incremental borrowing rates under its two operating leases. As the Partnership's leases do not provide an implicit rate, the Partnership estimated the incremental borrowing rates at the time the leases were entered into by utilizing the rate of the Partnership's secured debt and adjusting it for factors that reflect the profile of borrowing over the 30-year and 21.4-year expected lease terms, respectively.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2024. This evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures were effective as of December 31, 2024 at the reasonable assurance level in producing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosures.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2024 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission "2013 Framework" (COSO). Based on that evaluation, as of December 31, 2024, our management concluded that our internal control over financial reporting was effective at a reasonable assurance level based on those criteria. No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Ernst & Young, LLP, the independent registered public accounting firm who audited the Partnership’s consolidated financial statements included in this Annual Report on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting, which is included herein.

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Report of Independent Registered Public Accounting Firm

The Partners of Natural Resource Partners L.P.

Opinion on Internal Control Over Financial Reporting

We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Natural Resource Partners L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2024 and 2023, the related consolidated statements of comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2024, and the related notes and our report dated February 28, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2025

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ITEM 9B. OTHER INFORMATION

During the fiscal quarter ended December 31, 2024, none of our officers or directors, as defined in Rule 16a-1(f), informed us of the adoption, modification or termination of any "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as those terms are defined in Item 408 of Regulation S-K.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER AND CORPORATE GOVERNANCE

As a master limited partnership, we do not employ any of the people responsible for the management of our properties. Instead, we reimburse affiliates of our managing general partner, GP Natural Resource Partners LLC, for their services. The following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC as of the date of this Annual Report on Form 10-K. Each officer and director is elected for their respective office or directorship on an annual basis. RCM is entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC.

Name	Age	Position with the General Partner
Corbin J. Robertson, Jr.	77	Chairman of the Board and Chief Executive Officer
Craig W. Nunez	63	President and Chief Operating Officer
Christopher J. Zolas	50	Chief Financial Officer
Kevin J. Craig	56	Executive Vice President
Philip T. Warman	54	General Counsel and Secretary
Gregory F. Wooten	68	Senior Vice President, Chief Engineer
Galdino J. Claro	65	Director
Paul B. Murphy, Jr.	65	Director
Richard A. Navarre	64	Director
Corbin J. Robertson, III	54	Director
Stephen P. Smith	63	Director
Leo A. Vecellio, Jr.	78	Director

Corbin J. Robertson, Jr. has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC since 2002. Mr. Robertson, Jr. has vast business experience having founded and served as a director and as an officer of multiple companies, both private and public, and has served on the boards of numerous non-profit organizations. He has served as the Chief Executive Officer and Chairman of the Board of the general partner of Great Northern Properties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978, as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986, and the general partner of Western Pocahontas Properties Limited Partnership since 1986. Mr. Robertson, Jr. is also Chief Executive Officer and a member of the Board of Managers of Pocahontas Royalties LLC. He also served as a Principal with Quintana Capital Group until 2023. Mr. Robertson, Jr. is Chairman of the Board of the Cullen Trust for Higher Education, Chairman of the Board of KLX Energy Services Holdings, Inc. and is on the boards of the American Petroleum Institute, the National Petroleum Council, the Baylor College of Medicine and the Spirit Golf Association. In 2006, Mr. Robertson, Jr. was inducted into the Texas Business Hall of Fame. Mr. Robertson, Jr. is the father of Corbin J. Robertson, III.

Craig W. Nunez has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since August 2017 and previously served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC from January 2015 to August 2017. Prior to joining NRP, Mr. Nunez was an owner and Chief Executive Officer of Bocage Group, a private investment company specializing in energy, natural resources and master limited partnerships since March 2012. In addition, until joining NRP, he was a FINRA-registered Investment Advisor Representative with Searle & Co since July 2012 and served as an Executive Advisor to Capital One Asset Management since January 2014. From September 2011 through March 2012, Mr. Nunez served as the Executive Vice President and Chief Financial Officer of Quicksilver Resources Canada, Inc. Mr. Nunez was Senior Vice President and Treasurer of Halliburton Company from January 2007 until September 2011, and Vice President and Treasurer of Halliburton Company from February 2006 to January 2007. Prior to that, he was Treasurer of Colonial Pipeline Company from November 1995 to February 2006. Mr. Nunez has been involved in numerous charitable organizations and currently serves on the boards of Goodwill Industries of Houston and Medical Bridges, Inc.

Christopher J. Zolas has served as Chief Financial Officer since August 2017 and also served as Treasurer from August 2017 until May 2023. Mr. Zolas served as Chief Accounting Officer of GP Natural Resource Partners LLC from March 2015 to August 2017. Prior to joining NRP, Mr. Zolas served as Director of Financial Reporting at Cheniere Energy, Inc., a publicly traded energy company, where he performed financial statement preparation and analysis, technical accounting and SEC reporting for five separate SEC registrants, including a master limited partnership. Mr. Zolas joined Cheniere Energy, Inc. in 2007 as Manager of SEC Reporting and Technical Accounting and was promoted to Director in 2009. Prior to joining Cheniere Energy, Inc., Mr. Zolas worked in public accounting with KPMG LLP from 2002 to 2007.

Kevin J. Craig was named Executive Vice President of GP Natural Resource Partners LLC in February 2021, after serving as Executive Vice President, Coal of GP Natural Resource Partners LLC since September 2014. Mr. Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr. Craig also represents NRP as one of its appointees to the Board of Managers of Sisecam Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX Transportation. He has extensive marketing, finance and operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates, having been elected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate Craig served as Chairman of the Committee on Energy. Mr. Craig did not seek re-election in 2014 and his term ended in January 2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig has served as the Chairman of the Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber of Commerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He serves as a member of the Board of Directors of Encova Mutual Insurance Company, the West Virginia University Board of Governors and the WVU Medicine Board of Governors.

Philip T. Warman has served as General Counsel and Secretary of GP Natural Resource Partners LLC since August 2021. Mr. Warman previously served as Executive Vice President, General Counsel and Secretary of SandRidge Energy Inc. from August 2010 until June 2019. He was Associate General Counsel for SEC and finance matters for Spectra Energy Corporation from January 2007 through July 2010. From 1998 through 2006 he practiced law as a corporate finance attorney with Vinson & Elkins, LLP in Houston, Texas. Mr. Warman earned a Bachelor of Science in Chemical Engineering from the University of Houston in 1993 and graduated from the University of Texas School of Law in 1998.

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Gregory F. Wooten was named Senior Vice President, Chief Engineer of GP Natural Resource Partners LLC in February 2021, after serving as Vice President, Chief Engineer of GP Natural Resource Partners LLC since December 2013. Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP, Mr. Wooten served as Vice President, Chief Operating Officer and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties from 1982 until 2007. Mr. Wooten has over 35 years of experience in the coal industry, working as a planning and production engineer and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers. Mr. Wooten also serves as the President of the National Council of Coal Lessors and is a board member of the West Virginia, Kentucky, Indiana and Montana Coal Council. He also serves on the board of the Cabell-Huntington Hospital and is a member of the West Virginia School Building Authority.

Galdino J. Claro joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Claro has 30 years of worldwide executive leadership experience in the primary and secondary metals industries and is currently the Chief Executive Officer of the Wilmington Paper Corporation and an Independent Director of Phoenix Global. From October 2013 to August 2017, Mr. Claro served as the Group Chief Executive Officer and Managing Director of Sims Metal Management where he was also a member of the Safety, Health, Environment and Sustainability Committee, the Nomination Governance Committee and the Finance Investment Committee. Before joining Sims Metal Management, Mr. Claro served for four years as the Chief Executive Officer of Harsco Metals and Minerals. He joined Harsco from Aleris, where he served as CEO of Aleris Americas. Before that, he was the CEO of the Metals Processing Group of Heico Companies LLC. During his career with Alcoa Inc., Mr. Claro served for five years as the President of Alcoa China and for six years in Europe as the Vice President of Soft Alloys Extrusions and the President of Alcoa Europe Extrusions. While in South America, Mr. Claro worked for several different divisions of Alcoa Alumni SA as plant manager, technology manager, new products development director and Managing Director of Alcoa Cargo-Van. Before joining Alcoa in 1985, Mr. Claro started his career at Honda-Motogear as a Quality Control Manager where he worked for three years in both Brazil and Japan.

Paul B. Murphy, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Murphy retired from Cadence Bank in April 2023 after a 42-year career as a commercial banker serving 21 of those years as a CEO. Mr. Murphy helped raise $1 billion to invest in the distressed banking industry in 2010. He acquired Cadence Bank and three others and had strong core growth reaching $18 billion in assets. In 2021 Cadence merged with BancorpSouth and today the company is $48 billion in assets with 400 branches in 9 states and trades on the NYSE (CADE). Previously, Mr. Murphy spent 20 years at Amegy Bank of Texas, helping to steer that institution from $75 million in assets and a single location to assets of $11 billion and 85 banking centers at the time of his departure as the Chief Executive Officer and a Director in 2009. Mr. Murphy is an advocate of the community and is a board member of Oceaneering International, Inc., Hope and Healing Center and Institute and the Houston Hispanic Chamber of Commerce. He previously served on the Board of the Houston branch of the Dallas Federal Reserve and the Houston Endowment.

Richard A. Navarre joined the Board of Directors of GP Natural Resource Partners LLC in October 2013. Mr. Navarre brings extensive operating, financial, strategic planning, public company and coal industry experience to the Board of Directors. Mr. Navarre is former Chairman, President and CEO of Covia Holdings, a leading provider of high quality minerals and material solutions for the industrial and energy markets. From 1993 until 2012, Mr. Navarre held senior executive positions with Peabody Energy Corporation, including President-Americas, President and Chief Commercial Officer, Executive Vice President of Corporate Development and Chief Financial Officer. Mr. Navarre serves on the Board of Directors of Civeo Corporation, where he serves as Chairman and member of the Environmental, Social, Governance and Nominating Committee and Core Natural Resources, where he serves as Lead Independent Director, Governance Committee Chair, and Compensation Committee Member. He is a member of the Hall of Fame of the College of Business and a member of the Board of Advisors of the College of Business and Analytics of Southern Illinois University Carbondale. He is the former Chairman of the Bituminous Coal Operators’ Association. Mr. Navarre is a Certified Public Accountant. Mr. Navarre also has been involved in numerous civic and charitable organizations throughout his career.

Corbin J. Robertson, III joined the Board of Directors of GP Natural Resource Partners LLC in May 2013. Mr. Robertson, III is currently Principal, co-owner and director of Quintana Minerals Corporation and sole owner of CIII Capital Management, LLC, the primary investment vehicles for Mr. Robertson and his family’s investments in various industries. He has over 30 years of experience in private equity and investing. ​Mr. Robertson, III is Vice President and on the Board of Managers of the general partner of Western Pocahontas Properties Limited Partnership, an affiliate of NRP, and previously served as it's CEO through 2023. ​Previously, Mr. Robertson was the co-Managing Partner of LKCM Headwater Investments GP, LLC, a billion dollar plus private equity firm he co-founded with Luther King Capital Management investing in industrial distribution, financial services, energy, consumer products and healthcare businesses. Mr. Robertson began his career as a business analyst for Deloitte & Touche Consulting Group LLP and has worked in the private equity/principal investing industry since 1995. Mr. Robertson has founded or acquired multiple successful businesses in his career prior to co-founding Headwater. Mr. Robertson is currently a Board member of Sunnova Energy International Inc. (NYSE: NOVA), Independent Life Insurance Company, and multiple private boards of Quintana Minerals Corporation affiliated/CIII Capital Management portfolio companies. Mr. Robertson also sits on a couple of philanthropic boards, Texas Parks & Wildlife Foundation and the University of Texas Development Board.​ Mr. Robertson graduated with a Bachelor of Arts in the nationally recognized Plan II Liberal Arts Honors program and two Bachelors of Business Administration in Business Honors and Finance from University of Texas at Austin and holds a Masters of Business Administration from Harvard Business School.

Stephen P. Smith joined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive public company financial experience in the power and energy industries to the Board of Directors. Mr. Smith formerly served as Chief Financial Officer, Chief Accounting Officer and Director of the general partner of Columbia Pipeline Partners L.P. from September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and Chief Financial Officer of Columbia Pipeline Group from July 2015 to June 2016. Mr. Smith served as Executive Vice President and Chief Financial Officer for NiSource, Inc. from August 2008 to June 2015. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc, including Senior Vice President - Shared Services from January 2008 to June 2008, Senior Vice President and Treasurer from January 2004 to December 2007, and Senior Vice President - Finance from April 2003 to December 2003.

Leo A. Vecellio, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings extensive experience in the aggregates and coal mine development industry to the Board of Directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the late 1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer, contractor and oil terminal developer/operator in the Mid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with Vecellio & Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996 to November 2002. Mr. Vecellio is the former Chairman of the American Road and Transportation Builders and is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations.

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Corporate Governance

Board Meetings and Executive Sessions

The Board of Directors met eight times in 2024. During 2024, our non-management directors met in executive sessions several times. The presiding director was Mr. Vecellio, the Chairman of our Compensation, Nominating and Governance Committee, or CNG Committee. In addition, our independent directors met several times in executive session in 2024. Mr. Vecellio was the presiding director at those meetings. Interested parties may communicate with our non-management directors by writing a letter to the Chairman of the CNG Committee, NRP Board of Directors, 1415 Louisiana Street, Suite 3325, Houston, Texas 77002.

Independence of Directors

The Board of Directors has affirmatively determined that Messrs. Claro, Navarre, Smith, and Vecellio are independent based on all facts and circumstances considered by the Board of Directors, including the standards set forth in Section 303A.02(a) of the NYSE’s listing standards. Because we are a limited partnership as defined in Section 303A of the NYSE’s listing standards, we are not required to have a majority of independent directors on the Board of Directors. The Board of Directors has an Audit Committee, a CNG Committee and a Conflicts Committee, each of which is staffed solely by independent directors.

Audit Committee

Our Audit Committee is comprised of Mr. Smith, who serves as chairman, Mr. Claro and Mr. Navarre. Mr. Smith and Mr. Navarre are "Audit Committee Financial Experts" as determined pursuant to Item 407 of Regulation S-K. During 2024, the Audit Committee met six times.

Report of the Audit Committee

Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements of the New York Stock Exchange. The Audit Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements. The Audit Committee Charter is available on our website at www.nrplp.com and is available in print upon request.

During 2024, at each of its meetings, the Audit Committee met with the senior members of our financial management team, our general counsel and our independent auditors. The Audit Committee had private sessions at certain of its meetings with our independent auditors and the senior members of our financial management team and the general counsel at which candid discussions of financial management, accounting and internal control and legal issues took place.

The Audit Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 2024 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our financial reporting.

Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference for conservative policies when a range of accounting options is available.

The Audit Committee has discussed with the independent auditors the matters required to be discussed by the applicable requirements of the Public Company Accounting Oversight Board (“PCAOB”) and the Commission. The Audit Committee has received the written disclosures and the letter from the independent accountant required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the Audit Committee concerning independence, and has discussed with the independent accountant the independent accountant’s independence.

In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Audit Committee reviews our Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K prior to filing with the Securities and Exchange Commission. In 2024, the Audit Committee also reviewed quarterly earnings announcements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Audit Committee relies on the work and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report, express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting principles.

In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, and the Board of Directors has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2024, for filing with the Securities and Exchange Commission.

Stephen P. Smith, Chairman

Galdino J. Claro

Richard A. Navarre

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Compensation, Nominating and Governance Committee

Executive officer compensation is administered by the CNG Committee, which is currently comprised of three members: Mr. Vecellio, as Chairman, Mr. Navarre and Mr. Smith. During 2024, the CNG Committee met four times. Our Board of Directors appoints the CNG Committee and delegates to the CNG Committee responsibility for:

• reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates to our business;

• reviewing and recommending the annual and long-term incentive plans in which our executive officers participate and approving awards thereunder; and

• reviewing and approving compensation for the Board of Directors.

Our Board of Directors has determined that each CNG Committee member is independent under the listing standards of the NYSE and the rules of the SEC.

Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the design and implementation of compensation programs for directors and executive officers and other data that the CNG Committee considers as appropriate. In addition, the CNG Committee has the sole authority to retain and terminate any outside counsel or other experts or consultants engaged to assist it in the evaluation of compensation of our directors and executive officers. The CNG Committee Charter is available in print upon request.

Partnership Agreement

Investors may view our partnership agreement and the amendments to the partnership agreement on our website at www.nrplp.com. The partnership agreement is also filed with the SEC and is available in print to any unitholder that requests them.

Corporate Governance Guidelines and Code of Business Conduct and Ethics

We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that applies to our management, and complies with Item 406 of Regulation S-K. Our Corporate Governance Guidelines and our Code of Business Conduct and Ethics are available on our website at www.nrplp.com and are available in print upon request. We intend to disclose future amendments to certain provisions of the Code of Business Conduct and Ethics, and waivers of the Code of Business Conduct and Ethics granted to executive officers and directors, on the website within four business days following the date of the amendment or waiver.

NYSE Certification

Pursuant to Section 303A of the NYSE Listed Company Manual, in 2024, Corbin J. Robertson, Jr. certified to the NYSE that he was not aware of any violation by the Partnership of NYSE corporate governance listing standards.

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ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. Our executive officers based in Houston, Texas are employed by Quintana Minerals Corporation (“Quintana”), and our executive officers based in Huntington, West Virginia are employed by Western Pocahontas Properties Limited Partnership (“Western Pocahontas”). Quintana and Western Pocahontas are controlled by our Chairman and Chief Executive Officer and are affiliates of NRP. While our executive officers are employed by affiliates of NRP, each of them has been appointed to serve as an executive officer of GP Natural Resource Partners LLC (“GP LLC”), the general partner of NRP (GP) LLC (“NRP GP”), the general partner of NRP. For a more detailed description of our structure, see "Items 1. and 2. Business and Properties—Partnership Structure and Management" in this Annual Report on Form 10-K.

Although our executives’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse those companies based on the time allocated to NRP by each executive officer. Our reimbursement for the compensation of executive officers is governed by our partnership agreement. For purposes of this Compensation Discussion and Analysis, our “named executive officers” are:

• Corbin J. Robertson, Jr.—Chairman and Chief Executive Officer

• Craig W. Nunez—President and Chief Operating Officer

• Christopher J. Zolas—Chief Financial Officer

• Philip T. Warman—General Counsel and Secretary

• Kevin J. Craig—Executive Vice President

Executive Officer Compensation Strategy and Philosophy

Under our partnership agreement, each quarter we are required to distribute all of our available cash, as such term is defined in our partnership agreement. 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 are necessary for future operating and capital needs. Our primary objective over the last eight years has been to use all internally generated cash flow to reduce debt while paying distributions to common unitholders sufficient to cover income tax liability on their share of the partnership’s taxable income. Our compensation philosophy is designed to attract, motivate and retain highly talented executives, while keeping them focused on promoting our strategic objectives to manage the business under current market conditions and position the partnership as a key beneficiary of the transitional energy economy of the future. Our objective in determining the compensation of our executive officers is to incentivize them to create long-term value for our unitholders and other stakeholders. We believe our compensation programs encourage sustained long-term profitability by making a portion of each executive officer’s total direct compensation variable and dependent on our achievement of safety, financial and strategic performance goals as well as the total unitholder return of our common units. Thus, a significant portion of our executives’ total compensation is performance-based and not guaranteed, as further described under “—Components of Compensation.”

Although we reimburse Quintana and Western Pocahontas, as applicable, for the applicable portion of our executive officers’ compensation, the CNG Committee is responsible for administering our executive officer compensation programs. To help retain and motivate executives, the CNG Committee aims to offer competitive compensation packages through a mix of cash and long-term, equity-based incentives. The CNG Committee does not have any formal policies for allocating total compensation among the various components. Instead, the CNG Committee uses its judgment, in consultation with the independent compensation consultant, to establish an appropriate balance of short-term and long-term compensation for such executive officers for their services to us. The balance may change from year to year based on the amount of time an executive spends in service to us, our corporate strategy, financial performance and non-financial objectives, among other considerations.

Summary of Compensation Practices

We strive to maintain judicious governance standards and compensation practices by regularly reviewing best practices. The CNG Committee incorporated many best practices when forming our 2024 compensation program, including the following:

What We Do

✔	Align our executive compensation with long-term performance
✔	Align executives’ interests with those of unitholders
✔	Engage an independent compensation consultant, NFP Compensation Consultants ("NFP"), to assess our practices
✔	Maintain trading policies that restrict all employees and directors from pledging or short selling our securities, entering into any derivative transactions with respect to our securities, or otherwise hedging the risk and rewards of our securities
✔	Review the independence of any compensation consultant that is engaged to assist in our compensation analysis
✔	Provide limited perquisites

What We Don’t Do

✘	Automatically increase salaries each year or make lock-step changes in compensation based on peer group compensation levels or metrics
✘	Pay guaranteed or multi-year cash bonuses
✘	Provide significant perquisites
✘	Provide tax gross-ups

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The 2024 compensation for executive officers consisted of four primary components:

• base salaries;

• short-term cash incentive compensation;

• long-term equity incentive compensation; and

• perquisites and other benefits.

Mr. Robertson does not receive a salary in his capacity as Chief Executive Officer. Mr. Robertson is compensated through short-term cash and long-term equity incentive awards, all of which is allocated to NRP. To the extent other executive officers spend time on non-NRP matters, NRP bears only the proportionate cost of their base salaries, short-term cash incentive compensation and perquisites and other benefits.

In February of each year, the CNG Committee approves the short-term cash incentive awards for the year just ended and long-term incentive awards for the executive officers. The CNG Committee considers the performance of the partnership, the performance of the individuals and the outlook for the future in determining the amounts of the awards.

Each February, the CNG Committee also makes awards of equity-based awards to be settled in common units under the Natural Resource Partners 2017 Plan to NRP’s officers in order to incentivize management and align the long-term interests of management and NRP unitholders.

Role of the CNG Committee

The CNG Committee oversees our executive compensation and employee benefit programs, and reviews and approves all compensation decisions relating to our executive officers and directors. The CNG Committee also approves its report for inclusion in this Annual Report and has reviewed and discussed this Compensation Discussion and Analysis with management.

Specifically, the CNG Committee reviews and approves the compensation for our executive officers. It reviews and approves the annual and long-term incentive plans in which our executive officers participate, and it also reviews and approves compensation programs for the members of the Board of Directors, as described further below.

Role of Independent Compensation Consultant and Market Data

The CNG Committee engaged NFP to review our compensation practices for executive officers and directors relative to our peers. NFP provides no services to management or the CNG Committee that are unrelated to the duties and responsibilities of the CNG Committee, and the CNG Committee makes all decisions regarding the compensation of our executive officers and directors. NFP reports directly to the CNG Committee, and all work conducted by NFP for us is on behalf of the CNG Committee. The CNG Committee has determined that no conflicts of interest exist as a result of the engagement of NFP.

The CNG Committee, with input from NFP, selected our peer group (the “Peer Group”) after reviewing annual revenue, market capitalization, total enterprise value and total assets of relevant public companies to determine which companies were representative of the marketplace for talent within which we compete. The CNG Committee will review the Peer Group annually to ensure continued appropriateness for comparative purposes. The CNG Committee determined that the companies below reflect an appropriate Peer Group for 2024:

Amplify Energy Corp.	Falcon Minerals Corporation	SilverBow Resources, Inc.
Berry Corporation	Kimbell Royalty Partners, LP	Smart Sand, Inc.
Black Stone Minerals, L.P.	NACCO Industries, Inc.	SunCoke Energy, Inc.
Brigham Minerals, Inc.	PHX Minerals, Inc.	W&T Offshore Inc.
CatchMark Timber Trust, Inc.	Ramaco Resources, Inc.
CONSOL Coal Resources LP	Ranger Oil Corporation
Earthstone Energy Inc.	Ring Energy, Inc.

NFP provides the CNG Committee with Peer Group data for comparison purposes, such as to compare equity and pay mix practices. Market pay levels are one of multiple factors considered by the CNG Committee in setting applicable compensation amounts and determining the appropriate design of incentive compensation programs. The Peer Group used in 2024 is identical to the Peer Group used in 2023 except that companies that are no longer publicly traded were removed.

Role of Our Executive Officers in the Compensation Process

With respect to 2024 salaries and short-term cash incentive awards and long-term equity incentive awards, Mr. Nunez, our President and Chief Operating Officer, provided Mr. Robertson with recommendations relating to the executive officers other than himself. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of the executive officers other than himself. Messrs. Robertson and Nunez considered the factors described elsewhere in this Compensation Discussion and Analysis in recommending, in their discretion, the appropriate amounts of compensation for each executive officer (other than for themselves). Messrs. Robertson and Nunez attended the CNG Committee meetings, other than executive sessions called by the CNG Committee, at which the CNG Committee deliberated and approved the salaries, short-term cash incentive awards and long-term equity incentive awards for 2024. Messrs. Robertson and Nunez were excused from the meetings when the CNG Committee discussed their compensation.

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Components of Compensation

Base Salaries

With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our executive officers are paid an annual base salary by Quintana or Western Pocahontas for services rendered to us by the executive officers during the fiscal year. We then reimburse Quintana and Western Pocahontas based on the time allocated to our business by each executive officer. The base salaries of our executive officers are reviewed on an annual basis as well as at the time of a promotion or other material change in responsibilities. The CNG Committee reviews and approves the full salaries paid to each executive officer by Quintana and Western Pocahontas, based on both the actual time allocations to NRP in the prior year and the anticipated time allocations in the coming year. 

In determining salaries for NRP's executive officers for 2024, the CNG Committee considered several factors including the executive’s position and level of responsibility within our organization, comparative market data and other external market-based factors. The CNG Committee also considered the individual performance, our partnership’s overall performance during the fiscal year and the individual’s contribution to our overall performance of each member of the executive management team during 2023. Salaries for 2024 are shown in the Summary Compensation Table below.

Short-Term Cash Incentive Compensation

Short-term cash incentive awards are determined based on the Partnership meeting and exceeding certain annual financial, strategic objectives and safety goals. Short-term cash incentive awards are used to motivate and reward our executive officers. Each executive officer received a short-term cash incentive award approved in February 2025 by the CNG Committee. The amounts awarded with respect to 2024 under this program are disclosed in the Summary Compensation Table under the Bonus column. With respect to 2024, the CNG Committee, using recommendations from NFP, determined that cash bonuses would be paid based on a percentage of base salary, with our Chief Executive Officer (who is not paid a base salary) receiving a bonus target of approximately 2.3 times a deemed base salary of $556,973 (which is the base salary of our President and Chief Operating Officer). For 2024, the CNG Committee used free cash flow, strategic objectives and safety as performance measures in determining the amount of bonuses paid under the plan, representing 75%, 20% and 5% of the total award, respectively. Based on the level of achievement of the performance measures, the CNG Committee used its discretion to set the amount of bonus payments as a percentage of target.

The following table shows the performance measures used in the 2024 short-term cash incentive compensation for our executive officers, together with the percentage of the total annual cash incentive grant that such component comprises. Each of the components for the executive officers is described in greater detail below:              

Performance Measure	2024 Portion of Total Target Award
Free Cash Flow	75%
Strategic Objectives	20%
Safety	5%

We believe that these performance measures align our short-term incentive compensation with both unitholder and employee interests by targeting specific performance goals set forth in the first quarter of each year. By identifying meaningful performance measures, and by assigning greater weight to certain measures, we are able to more closely align compensation to the achievement of those business objectives over which particular employees have the greatest impact.

If the target level of performance is achieved with respect to a particular performance measure, the applicable payout percentage for that performance measure will equal 100%. Achievement at the threshold performance level results in a payout percentage for that performance measure that will equal 50%. If the maximum level of performance is achieved with respect to a particular performance measure the payout percentage for that measure will equal 200% of target performance, with the exception of safety which is capped at 100%. We interpolate payouts under the annual cash incentive awards for performance levels that fall between the threshold, target and maximum performance levels. There is no payout for performance that does not meet the threshold level criteria and there is no payout in excess of the maximum performance level.

Free Cash Flow

“Free Cash Flow” is calculated as cash flow from operating activities plus return on long-term contract receivable less cash flow used in investing activities, excluding proceeds from asset sales. Further, the CNG Committee determined that Free Cash Flow would be adjusted to exclude free cash flow received from Sisecam Wyoming and include the additional cash paid for interest on debt used for early settlement of outstanding warrants and preferred units. The CNG Committee utilized the budget approved by the Board during the annual review process and set the “target” level for this performance measure at 100% of budget. The threshold payout value was set at 80% of the Free Cash Flow budget and the maximum payout value was set at 120% of the budget. We consider this performance measure to be difficult to attain and appropriately reflective of our position in the inherently volatile commodities market. The following table shows the threshold, target and maximum levels for the 2024 short-term cash incentive compensation plan:

Performance Measure	Threshold	Target	Maximum
Free Cash Flow	$155,830,400	$194,788,000	$233,745,600

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Strategic Objectives

Strategic Objectives are approved by the Board of Directors each year and reflect the broad strategic objectives of the Partnership, which may change year to year. The measure of performance of these strategic objectives is evaluated annually by the CNG Committee and the threshold, target and maximum payouts are at the discretion of the CNG Committee.

Safety

Safety is an important emphasis for the Partnership and, the Board of Directors believes, each of the Partnership's stakeholders. Strong safety performance leads to improved employee performance and lower costs associated with regulatory citations, insurance and litigation matters, which in turn lead to improved operating performance. Because of these factors, the CNG Committee uses Reportable Injuries and Lost Time Incidents as a component of the annual incentive compensation plan. Due to the non-operating nature of our business, the “Reportable Injuries and Lost Time Incidents” are set at a target of zero, with threshold or maximum measure. Additionally, the CNG Committee considers the Partnership's completion rate for annual safety trainings with a 100% employee completion rate.

2024 Payout Under the Short-term Cash Incentive Compensation Plan

In early 2025, the CNG Committee evaluated the levels of achievement of the various performance measures for 2024 and made the following determinations:

Performance Measure	Actual Performance	Applicable Payout Percentage	Relative Weighting	Weighted Payout Percentage
Free Cash Flow	$217,849,000	159%	75%	119%
Strategic Objectives	Board Satisfaction	100%	20%	20%
Safety	100%	100%	5%	5%

Based on the actual performance as set forth above, the cumulative amounts listed below were earned under the 2024 short-term cash incentive compensation for the Partnership's 2024 performance.

Name	Target as a % of Base Salary	Actual payout as a % of Base Salary	Dollar Amount of Actual payout ($)
Corbin J. Robertson, Jr. (1)	2.3x	2.3x	1,844,693
Craig Nunez	100%	144%	802,040
Christopher J. Zolas	80%	115%	454,749
Philip Warman	76%	109%	432,012
Kevin Craig (2)	80%	115%	415,753

(1)	As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s actual payout.
(2)	Mr. Craig allocated approximately 94% of his time to NRP during the year ended December 31, 2024, and the amount of short-term cash incentive compensation reflects this allocation.

The following table shows the target opportunities available to the named executive officers as a percentage of base salary and the actual payouts as a percentage of their base salaries for each of the last three years:

	2022		2023		2024
Name	Target as % of Base Salary	Actual Payout as % of Target	Target as % of Base Salary	Actual Payout as % of Target	Target as % of Base Salary	Actual Payout as % of Target
Corbin J. Robertson, Jr. (1)	2.3x	195%	2.3x	185%	2.3x	144%
Craig Nunez	100%	195%	100%	185%	100%	144%
Christopher J. Zolas	80%	195%	80%	185%	80%	144%
Philip Warman	76%	195%	76%	185%	76%	144%
Kevin Craig	80%	195%	80%	185%	80%	144%

⁽¹⁾ As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s base salary.

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Long-Term Equity Incentive Compensation

We have adopted the 2017 Plan pursuant to which we may grant equity-based compensation to our executive officers and other officers. Our CNG Committee believes that awards under the 2017 Plan promote the alignment of the interests of management with those of our unitholders and promote creation of value for our unitholders. In 2023, the CNG Committee determined it was appropriate to introduce additional performance measures in connection with long-term compensation to better align executive compensation with the Partnership's performance. We refer to these awards issued in 2024 as “2017 Plan Phantom Units.” The 2024 awards were made in the form of phantom units that will settle (following vesting) in NRP common units on a one-for-one basis and will accrue tandem distribution equivalent rights (“DERs”) to be paid in cash upon settlement.

2024 Annual Grants

The award granted in February 2024 (“2024 Award”) provided a form of performance-based long-term incentive compensation. This award included a mix of time-based and performance-based phantom units awarded at target; 35% will time-vest ratably over a three-year period and 65% will cliff vest with the actual number of units issued vesting for each phantom unit to be determined by the performance score. The performance score shall be the relative total unit holder return (“TUR”) performance score plus the financial performance score, both weighted at 50%. The 2017 Plan Phantom Units are subject to forfeiture and will vest on an accelerated basis following death or disability of the award recipient, following a change in control of NRP, or termination without cause or for good reason. The grant date fair value of the 2017 Plan Phantom Units awarded in 2024 is disclosed in the Summary Compensation Table under the Stock Awards column. In determining the award amounts the CNG Committee used a percent target of base salary.

The following table sets forth the long-term equity award targets and number of units granted to each named executive officer in 2024:

	2024 Award
Named Executive Officer	Target as % of Base Salary	Time-Based	Performance-Based
Corbin J. Robertson, Jr. (1)	1.84x	8,267	15,354
Craig W. Nunez	224%	4,493	8,344
Christopher J. Zolas	153%	2,175	4,040
Philip T. Warman	85%	1,209	2,244
Kevin J. Craig	90%	1,244	2,311

⁽¹⁾ As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s base salary.

Relative Total Unitholder Return

For the relative TUR measure, the performance-based units will be eligible to vest based on the Partnership's TUR relative to the Partnership's performance peer group over the three-year performance period. The TUR calculation will be based on a “point-to-point” approach using the 20 calendar-day volume-weighted average of the closing price per share of the Partnership or a member of the peer group, as applicable, at the beginning and end of the performance period. In the event that our TUR is negative, the payout will be capped at target, regardless of peer group performance. In the instance of a merger, acquisition or delisting of a peer company during the performance period, the company would be removed from the peer group. The companies used for our performance peer group for the 2024 Award at the time of the grant are listed below:

Alliance Resource Partners, L.P.	Peabody Energy Corporation
Alpha Metallurgical Resources, Inc.	Ramaco Resources, Inc. (NYSE: METC)
Arch Resources, Inc.	Ramaco Resources, Inc. (NYSE: METCB)
CONSOL Coal Resources LP	SunCoke Energy, Inc.
Corsa Coal Corp.	Warrior Met Coal, Inc.
Enviva Inc.

If the target level of performance is achieved, the payout percentage will equal 100%. Achievement at the threshold performance level will result in a payout at 50% of target performance and achievement at the maximum performance level will result in a payout at 200% of target performance. We interpolate payouts for performance levels that fall between the stated performance levels. There is no payout for performance that does not meet the threshold level and there is no payout in excess of the maximum performance level. The following table shows the performance levels for the 2024 long-term performance-based equity awards:

Performance Measure	Threshold	Target	Maximum
Relative Total Unitholder Return	18th Percentile	45th Percentile	91st Percentile

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Financial Performance Score

The financial performance score is calculated based on cumulative three-year free cash flow. “Free Cash Flow” is defined as cash from operating activities plus return on long-term contract receivable less cash flow used in investing activities, excluding proceeds from asset sales. Payouts will be determined based on the achievement of cumulative free cash flow relative to targets set by the Committee. We consider this performance measure to be difficult to attain and appropriately reflective of our position in the inherently volatile commodities market.

Perquisites and Other Personal Benefits

Both Quintana and Western Pocahontas maintain employee benefit plans that provide our executive officers and other employees with the opportunity to enroll in health, dental and life insurance plans. Each of these benefit plans requires the employee to pay a portion of the health and dental premiums, with the company paying the remainder. These benefits are offered on the same basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee allocates time to our business.

In 2024, Quintana and Western Pocahontas maintained tax-qualified 401(k) plans. During 2024, Quintana and Western Pocahontas matched 100% of the first 6.0% of the employee contributions under their respective 401(k) plans. As with the other contributions, any amounts contributed by Quintana and Western Pocahontas are reimbursed by us based on the time allocated by the employee to our business. None of NRP, Quintana or Western Pocahontas maintains a pension plan or a defined benefit retirement plan.

Other Compensation Policies and Practices

Unit Ownership Requirements

NRP maintains Unit Ownership and Retention Guidelines (the “ownership guidelines”) that are administered by the CNG Committee and require NRP’s officers who are required to file ownership reports under Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and certain other officers as designated from time-to-time by the Board of Directors or the CNG Committee to retain all common units awarded under any NRP incentive plan (net of any units withheld or sold to cover tax liabilities) until certain ownership guidelines are met. The following table sets forth the ownership guidelines. There is no minimum time period required to achieve the unit ownership guidelines.

Position	Requirement
Chief Executive Officer (1)	N/A
President and Chief Operating Officer	3 x Salary
Chief Financial Officer	3 x Salary
General Counsel	1.5 x Salary
Executive Vice President	2 x Salary

⁽¹⁾ Ownership guidelines due not currently apply to our Chief Executive Officer due to his substantial ownership in NRP. 

The ownership guidelines also require directors who are not officers to retain common units with a value equal to three times the amount of the annual cash retainer paid to directors. Directors are required to achieve the unit ownership guideline within five years. Until the unit ownership guideline is achieved, each director is encouraged to retain all common units awarded under any NRP incentive plan (net of any units sold to cover tax liabilities).

Units that count towards the satisfaction of the officer and director guidelines include common units held directly by the executive officer or director, common units owned indirectly by the executive officer or director (e.g., by a spouse or other immediate family member residing in the same household or a trust for the benefit of the executive officer or director or his or her family), units granted under NRP’s long-term incentive plans (including phantom units representing the right to receive units) and units purchased in the open market (whether purchased before or after the effective date of the ownership guidelines). As of December 31, 2024, all executive officers were in compliance with ownership guidelines.

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Incentive Compensation Recoupment Policy

NRP maintains the Natural Resource Partners L.P. Incentive-Based Compensation Recoupment Policy, which is administered by the CNG Committee. The policy authorizes the Board of Directors or any committee thereof to recoup incentive compensation in the event of a restatement of financial statements due to material non-compliance with securities laws, fraud or misconduct. See policy at Exhibit 97.1 in this Annual Report on Form 10-K.

Securities Trading Policy

Our insider trading policy restricts employees and directors, as well as their designees, from purchasing or selling puts or calls to sell or buy our common units, engaging in short sales with respect to our common units, buying our securities on margin or pledging our securities to secure debt or engaging in any transactions that would be deemed to be a hedging transaction involving our securities. See policy as Exhibit 19.1 in this Annual Report on Form 10-K.

Policies and Practices Related to Stock Options

We do not currently grant, nor have we historically granted, stock options or similar awards as part of our equity compensation programs. If stock options or similar awards were to be granted in the future, NRP would not grant such options or similar awards in anticipation of the release of material nonpublic information that is likely to result in changes to the price of our common units. During fiscal year 2024, we did not time the disclosure of material nonpublic information for the purpose of affecting the value of executive compensation.

Risk Assessment of Compensation Plans

We believe that our compensation program does not encourage excessive or unnecessary risk taking. This is primarily due to the fact that our compensation programs and the compensation arrangements are designed to encourage our employees, including our executive officers, to focus on both short-term and long-term strategic goals, thereby creating an ownership culture and helping to align the interests of our employees and our unitholders. Accordingly, our compensation program is balanced between short-term and long-term incentives, as well as cash and equity-based forms of settlement.

Overall, we believe that the balance within our compensation program results in an appropriate compensation structure and that the program does not pose risks that could have a material adverse effect on our business or financial performance.

Report of the Compensation, Nominating and Governance Committee

The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management. Based on the reviews and discussions referred to in the foregoing sentence, the CNG Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2024.

Leo A. Vecellio, Jr., Chairman

Richard A. Navarre

Stephen P. Smith

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Summary Compensation Table

The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation for 2022, 2023 and 2024:

Name and Principal Position (1)	Year	Salary ($)		Bonus ($)		Stock Awards ($) (2)		All Other Compensation ($) (3)		Total ($)
Corbin J. Robertson, Jr.—Chief Executive Officer
	2024		—		1,844,693		2,142,425		—		3,987,118
	2023		—		2,369,918		5,638,047		—		8,007,965
	2022		—		2,379,068		3,096,757		—		5,475,825
Craig W. Nunez—President and Chief Operating Officer
	2024		556,973		802,040		1,164,316		20,700		2,544,029
	2023		556,973		1,030,400		3,064,159		19,800		4,671,332
	2022		530,450		1,034,378		1,683,020		18,300		3,266,148
Christopher J. Zolas—Chief Financial Officer
	2024		394,748		454,749		563,701		20,700		1,433,898
	2023		394,748		584,226		1,369,645		19,800		2,368,419
	2022		375,950		586,482		709,414		18,300		1,690,146
Philip T. Warman—General Counsel and Secretary (4)
	2024		394,748		432,012		313,187		20,700		1,160,647
	2023		394,748		555,015		849,337		19,800		1,818,900
Kevin J. Craig—Executive Vice President (5)
	2024		360,897		415,753		322,439		28,670		1,127,759
	2023		337,861		500,034		871,561		26,243		1,735,699

(1)

In 2024, Messrs. Robertson, Nunez, Zolas, Warman and Craig spent approximately 50%, 100%, 100%, 100% and 94%, respectively, of their time on NRP matters.

(2)

Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see "Item 8. Financial Statements and Supplementary Data—Note 16. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K for more information.

(3)	Includes portions of 401(k) matching allocated to Natural Resource Partners by Quintana and Western Pocahontas.
(4)	Mr. Warman was not a named executive officer in 2022.
(5)	Mr. Craig was not a named executive officer in 2022. Mr. Craig allocated approximately 94% of his time to NRP during the year ended December 31, 2024 and amounts included under the “Salary,” “Bonus” and “All Other Compensation” columns reflect this allocation. Amounts included under “Stock Awards” are paid 100% by NRP.

Grants of Plan-Based Awards in 2024

The following table shows the 2017 Plan Phantom Units granted to named executive officers during 2024. Based on the grant, the awards in the table below will either vest ratably in 2025, 2026 and 2027 or cliff vest in 2027. Upon settlement, an equivalent number of common units will be issued to each named executive officer, subject to withholding. The 2017 Plan Phantom Units also accrue DERs from the grant date, which will be paid out in cash upon settlement following and subject to vesting.

		2017 Plan Phantom Units
		Estimated Future Payouts Under Equity Incentive Plan Awards (1)			All other Unit Awards (2)
Named Executive Officer	Grant Date	Threshold (#)	Target (#)	Maximum (#)	Units (#)	Grant Date Fair Value ($)
Corbin J. Robertson, Jr	2/7/2024	7,677	15,354	30,708		1,392,608
	2/7/2024				8,267	749,817
Craig W. Nunez	2/7/2024	4,172	8,344	16,688		756,801
	2/7/2024				4,493	407,515
Christopher J. Zolas	2/7/2024	2,020	4,040	8,080		366,428
	2/7/2024				2,175	197,273
Philip T. Warman	2/7/2024	1,122	2,244	4,488		203,531
	2/7/2024				1,209	109,656
Kevin J. Craig	2/7/2024	1,156	2,311	4,622		209,608
	2/7/2024				1,244	112,831

(1)	The units represent performance-based awards and cliff vest in February 2027. The number of units that vest, if at all, will be between the threshold and maximum.
(2)	The units represent time-based awards and vest ratably in February 2025, 2026 and 2027.

Employment Agreements

None of our named executive officers have an employment agreement.

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Outstanding Equity Awards at December 31, 2024

The table below shows the total number of outstanding 2017 Plan Phantom Units held by each named executive officer at December 31, 2024. Performance-based units are valued assuming target is met.

Named Executive Officer	Unvested 2017 Plan Phantom Units	Market Value of Unvested 2017 Plan Phantom Units ($) (6)
Corbin J. Robertson, Jr. (1)	135,602	15,051,822
Craig W. Nunez (2)	73,697	8,180,367
Christopher J. Zolas (3)	33,228	3,688,308
Philip T. Warman (4)	17,847	1,981,017
Kevin J. Craig (5)	20,910	2,321,010

⁽¹⁾ 90,782 units are time-based and vest ratably in February 2025, 2026 and 2027, and 44,820 units are performance based and cliff vest in February 2026 and 2027.

⁽²⁾ 49,339 units are time-based and vest ratably in February 2025, 2026 and 2027, and 24,358 units are performance based and cliff vest in February 2026 and 2027.

⁽³⁾ 21,437 units are time-based and vest ratably in February 2025, 2026 and 2027, and 11,791 units are performance based and cliff vest in February 2026 and 2027.

(4)	11,311 units are time-based and vest ratably in February 2025, 2026 and 2027, and 6,536 units are performance based and cliff vest in February 2026 and 2027.
(5)	14,179 units are time-based and vest ratably in February 2025, 2026 and 2027, and 6,731 units are performance based and cliff vest in February 2026 and 2027.
(6)	Based on a unit price of $111.00, the closing price for the common units on December 31, 2024.

Units Vested in 2024

The table below shows the value realized by each named executive officer as a result of the vesting of their phantom unit awards granted under the 2017 Plan:

Named Executive Officer	2017 Plan Phantom Units	Value Realized on Vesting ($) (1) (2)
Corbin J. Robertson, Jr.	73,529	6,906,277
Craig W. Nunez	43,858	4,129,007
Christopher J. Zolas	20,791	1,961,680
Philip T. Warman	5,951	550,458
Kevin J. Craig	14,151	1,335,633

(1)	Based on a unit price of $86.91, the closing price for the common units on February 14, 2024.
(2)	Includes DERs accrued from the issue date to the settlement date.

Potential Payments upon Termination or Change in Control

Upon the occurrence of a change in control or termination without cause of NRP, our general partner, or GP Natural Resource Partners LLC, 2017 Plan Phantom Units held by each of our named executive officers would immediately vest and become payable and they are entitled to no other benefits because we do not have employment contracts. The table below indicates the estimated payments to each named executive officer following a change in control at December 31, 2024.

	2017 Plan Equity Awards
Named Executive Officer	Unvested Phantom Units	Market Value ($) (1)	Accumulated DERs ($)	Total Potential Payments ($)
Corbin J. Robertson, Jr.	135,602	15,051,822	1,328,258	16,380,080
Craig W. Nunez	73,697	8,180,367	721,886	8,902,253
Christopher J. Zolas	33,228	3,688,308	321,816	4,010,124
Philip T. Warman	17,847	1,981,017	167,271	2,148,288
Kevin J. Craig	20,910	2,321,010	205,593	2,526,603

⁽¹⁾ Calculated based on a unit price of $111.00, the closing price for the common units on December 31, 2024.

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Directors' Compensation for the Year Ended December 31, 2024

For more information regarding the Board of Directors and committees thereof, see “Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance” elsewhere in this Annual Report on Form 10-K. Director compensation during 2024 consisted of a $75,000 cash retainer and an award of common units under the 2017 Plan. The phantom units awarded to Board of Directors members in 2024 vest after one year; however, the Board of Directors members had the option in advance of receipt of the award to elect to defer settlement of the award until after 90 days following such director’s retirement or earlier departure from the Board of Directors. In addition, members of Board of Directors committees received $8,000, $7,500 and $5,000 for serving on the audit, CNG and conflicts committees, respectively, and the chairman of the audit, compensation, nominating and governance and conflicts committees received an additional $20,000, $15,000 and $15,000, respectively, for acting as chairman.

The table below shows the directors’ compensation for the year ended December 31, 2024:

Name of Director	Fees Earned or Paid in Cash ($)	2017 Plan Common Unit Awards ($) (1)	Total Compensation ($)
S. Reed Morian (2)	37,500	115,021	152,521
Richard A. Navarre (3)	110,500	115,021	225,521
Corbin J. Robertson, III	75,000	115,021	190,021
Stephen P. Smith (4)	110,500	115,021	225,521
Leo A. Vecellio, Jr.	102,500	115,021	217,521
Paul B. Murphy, Jr.	75,000	115,021	190,021
Galdino J. Claro	88,000	115,021	203,021

⁽¹⁾ Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see "Item 8. Financial Statements and Supplementary Data—Note 16. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K. All of the phantom units reported in this column were outstanding on December 31, 2024 and will vest on February 7, 2025. As of December 31, 2024, each of the current directors hold the following number of outstanding phantom unit awards: Mr. Navarre, 5,537; Mr. Robertson, 1,183; Mr. Smith, 19,265; Mr. Vecellio, 1,183; Mr. Murphy, 1,183 and Mr. Claro, 1,183.

(2)	Mr. Morian passed away in April 2024 at which time his phantom units awarded in February 2024 were forfeited.
(3)	Mr. Navarre elected to defer settlement of his common units awarded under the 2017 Plan in 2018 and 2019 until 90 days following his retirement or earlier departure from the Board of Directors. As of December 31, 2024, 5,537 phantom units previously awarded to Mr. Navarre were outstanding but only 1,183 were unvested.

⁽⁴⁾ Mr. Smith elected to defer settlement of his common units awarded under the 2017 Plan in 2018, 2019, 2020, 2021 and 2022 until 90 days following his retirement or earlier departure from the Board of Directors. As of December 31, 2024, 19,265 phantom units previously awarded to Mr. Smith were outstanding but only 1,183 were unvested.

Compensation Committee Interlocks and Insider Participation

During the year ended December 31, 2024, Messrs. Vecellio, Navarre, and Smith served on the CNG Committee. None of Messrs. Vecellio, Navarre and Smith has ever been an officer or employee of NRP or GP LLC. None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has any executive officer serving as a member of our Board or CNG Committee.

Pay Ratio Disclosure

The Securities and Exchange Commission has adopted a rule requiring annual disclosure of the ratio of the median employee’s total annual compensation to the total annual compensation of the principle executive officer.

The personnel providing services to us, including our executive officers, are employed by Quintana or Western Pocahontas. As of December 31, 2024, 54 such persons were providing services to us. We identified a new median service provider for 2024 by examining the 2024 total taxable compensation, as reflected in our payroll records as reported to the Internal Revenue Service on Form W-2, for all individuals who provided services to us as of December 31, 2024. We did not make any assumptions, adjustments or estimates with respect to total cash compensation or equity compensation and we did not annualize the compensation for any service providers that were not employed for all of 2024.

After identifying the median service provider based on total compensation, we calculated annual 2024 compensation for the median service provider using the same methodology used to calculate the Chief Executive Officer’s total compensation as reflected in the Summary Compensation Table above. The median service provider’s annual 2024 compensation was as follows:

Name	Year	Salary ($)	Bonus ($)	Non-Equity Incentive Plan Compensation ($)	Stock Awards ($)	All Other Compensation ($)	Total ($)
Median Service Provider	2024	182,514	—	17,693	—	9,330	182,514

Our 2024 ratio of Chief Executive Officer total compensation of $3,987,118 to our median service provider's total compensation of $182,514 is reasonably estimated to be 22:1.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following tables set forth, as of February 14, 2025, the amount and percentage of our common units beneficially held by (1) each person known to us to beneficially own 5% or more of any class of our units, (2) by each of our directors and named executive officers and (3) by all directors and executive officers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the units shown.

			Percentage of
	Common		Common
Name of Beneficial Owner	Units		Units (1)
Corbin J. Robertson, Jr. (2)		2,604,255		19.8	%
Quintana Management LLC (3)		1,883,986		14.3	%
The Goldman Sachs Group, Inc. (4)		685,315		5.2	%
Kevin J. Craig		40,505		*
Craig W. Nunez		108,474		*
Philip T. Warman		8,411		*
Christopher J. Zolas		51,958		*
Galdino J. Claro		21,292		*
Paul B. Murphy, Jr.		23,985		*
Richard A. Navarre (5)		18,178		*
Corbin J. Robertson III (6)		255,834		1.9	%
Stephen P. Smith (7)		3,805		*
Leo A. Vecellio, Jr.		23,532		*
Directors and Officers as a Group (8)		3,197,492		24.3	%

* Less than one percent.

(1) 13,138,097 common units issued and outstanding as of February 14, 2025.

(2) Mr. Robertson, Jr. may be deemed to beneficially own 703,955 common units owned in his capacity as controlling owner of Quintana Holdings, LP, 1,727,986 common units in his capacity as controlling member of Quintana Management LLC, which is the sole member of Western Pocahontas GP LLC, which is the general partner of Western Pocahontas Properties Limited Partnership, 156,000 common units in his capacity as the controlling member of Quintana Management LLC, which is the sole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource Partners LLC, which is the general partner of NRP (GP) LP, 11,021 common units in his capacity as controlling shareholder of Western Pocahontas Corporation, and 5,293 common units in his capacity as controlling shareholder of GNP Management Corporation. Mr. Robertson, Jr.’s address is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.

(3) Quintana Management LLC has voting and dispositive power with respect to 1,727,986 common units in its capacity as sole member of Western Pocahontas GP LLC, which is the general partner of Western Pocahontas Properties Limited Partnership and 156,000 common units in its capacity as the sole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource Partners LLC, which is the general partner of NRP (GP) LP. The business address of Quintana Management LLC is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.

(4) According to a Schedule 13G/A filing with the SEC on November 7, 2024, The Goldman Sachs Group holds shared voting power and shared dispositive power with respect to 685,315 common units in the Partnership. The business address of The Goldman Sachs Group is 200 West Street, New York, NY 10282.

(5) Does not include 4,354 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Navarre has elected to defer settlement of until 90 days following the date that he no longer serves on NRP’s Board of Directors.

(6) Mr. Robertson III may be deemed to beneficially own 9,783 common units held by CIII Capital Management, LLC, 10,000 common units held by BHJ Investments LP, 19,663 common units held by The Corbin James Robertson III, 2009 Family Trust and 39 common units held by his spouse, Brooke Robertson. The address for CIII Capital Management, LLC, BHJ Investments LP, and The Corbin James Robertson III, 2009 Family Trust is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. The following common units are pledged as collateral for loans: 68,873 common units owned by Mr. Robertson III.

(7) Does not include 18,082 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Smith has elected to defer settlement of until 90 days following the date that he no longer serves on NRP’s Board of Directors. Mr. Smith may be deemed to beneficially own 2,622 common units owned by the SP Smith 2002 Revocable Trust.

⁽⁸⁾ NRP’s directors and executive officers as a group consists of 12 individuals.

Securities Authorized for Issuance under Equity Compensation Plans

The following table shows the securities authorized for issuance under our 2017 Long-Term Incentive Plan as of December 31, 2024. 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. 

	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan Category	(a)		(b)		(c)
Equity compensation plans approved by security holders		—		—		720,957 (1	)
Equity compensation plans not approved by security holders		n/a		n/a		n/a
Total		—		—		720,957

⁽¹⁾ As of December 31, 2024, 349,764 of the 2017 Plan Phantom Units were outstanding. Each 2017 Plan Phantom Units represents the right to receive one common unit, together with associated distribution equivalent rights.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Relationships with Entities Associated with Corbin J. Robertson, Jr.

Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, and Great Northern Properties Limited Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the "WPP Group". Corbin J. Robertson, Jr. controls the general partner of Western Pocahontas Properties, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman and Chief Executive Officer of New Gauley Coal Corporation.

Omnibus Agreement

As part of the omnibus agreement entered into concurrently with the closing of our initial public offering (the "Omnibus Agreement"), the WPP Group and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the “GP affiliates,” each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a "restricted business") in the specific circumstances described below:

• the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal within the United States; and

• the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal within the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.

"Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group and its controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us.

A GP affiliate may, directly or indirectly, engage in a restricted business if:

• the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.

• the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.

• the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under the procedures described below.

• its ownership in the restricted business consists solely of a non-controlling equity interest.

For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate.

The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in by the WPP Group at closing of our initial public offering (and except as described below under "—Pocahontas Royalties LLC"), may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be acquired.

If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer us the opportunity to purchase the restricted business within six months of acquisition.

For purposes of this paragraph, "restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restriction summarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate.

If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate may operate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.

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If, at the end of the two-year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will be under no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned.

In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offer procedures described above will recommence.

If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly held limited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPP Group may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures described above.

The Omnibus Agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of the WPP Group under the Omnibus Agreement terminate when the WPP Group and its affiliates cease to participate in the control of the general partner. For more information, see the Omnibus Agreement attached as Exhibit 10.3 to this Annual Report on Form 10-K.

Pocahontas Royalties LLC

On February 28, 2020, Pocahontas Royalties LLC (“Pocahontas Royalties”) completed the acquisition of a private company that owns approximately one million acres of mineral rights and leases coal to coal mine operators in Central Appalachia. Pocahontas Royalties is controlled by Corbin J. Robertson, Jr. and members of his family. Reed Morian, one of the former directors of GP Natural Resource Partners LLC, also serves on the Board of Managers of Pocahontas Royalties.

In connection with the closing of the acquisition, we and Pocahontas Royalties entered into a limited waiver of the Omnibus Agreement pursuant to which we waived the provision of the Omnibus Agreement that restricts Mr. Robertson, Jr. and his affiliates (other than NRP) from owning, operating or investing in fee coal in the United States with an aggregate fair market value in excess of $75 million. Mr. Robertson had previously offered NRP the opportunity to participate in the acquisition and we determined, after due consideration, not to participate.

In addition, on February 28, 2020, we and Pocahontas Royalties entered into a right of first offer agreement pursuant to which Pocahontas Royalties granted us the exclusive right of first offer to purchase any assets (or entities holding such assets) proposed to be sold at any time by Pocahontas Royalties or any of its subsidiaries with a fair market value exceeding $2 million (individually or in the aggregate), excluding surface acreage, assets or rights (other than surface rights that are appurtenant to or necessary for the development of mineral rights). Provided that Pocahontas Royalties has provided us the opportunity to make a first offer within the time periods specified in the agreement, Pocahontas Royalties will be under no obligation to accept any offer timely made by us and may determine, in its sole discretion, to consummate a transaction with a third party free and clear of any obligations to us.

Office Building in Huntington, West Virginia

We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The initial 10-year term of the lease expired at the end of 2018. On January 1, 2019, we entered into a new lease on the building for a five-year base term, with five additional five-year renewal options. We paid approximately $0.8 million to Western Pocahontas under the lease during the year ended December 31, 2024.

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Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group and Pocahontas Royalties) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLC have duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage our Partnership in a manner beneficial to us and our unitholders. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the "Delaware Act", provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions modifying the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the Board of Directors of such resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:

• approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or course of action that has not received approval;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement, consider:

• the relative interests of any party to such conflict and the benefits and burdens relating to such interest;

• any customary or accepted industry practices or historical dealings with a particular person or entity;

• generally accepted accounting practices or principles; and

• such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

Conflicts of interest could arise in the situations described below, among others.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

• amount and timing of asset purchases and sales;

• cash expenditures;

• borrowings;

• the issuance of additional common units; and

• the creation, reduction or increase of mineral rights in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of enabling our general partner to receive distributions.

For example, in the event we have not generated sufficient cash from our operations to pay the quarterly distribution on our common units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding common units.

The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries.

We do not have any officers or employees. We rely on officers and employees of GP Natural Resource Partners LLC and its affiliates.

We do not have any officers or employees and rely on officers and employees of GP Natural Resource Partners LLC and its affiliates. Affiliates of GP Natural Resource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource Partners LLC are not required to work full time on our affairs. Certain of these officers devote significant time to the affairs of the WPP Group or its affiliates and are compensated by these affiliates for the services rendered to them.

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We reimburse our general partner and its affiliates for expenses.

We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-length negotiations.

The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length negotiations.

All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us.

Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

We may not choose to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.

Our general partner’s affiliates may compete with us.

The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement and the Omnibus Agreement, affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us.

The Conflicts Committee Charter is available upon request.

Director Independence

For a discussion of the independence of the members of the Board of Directors of our managing general partner under applicable standards, see "Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance—Corporate Governance—Independence of Directors," which is incorporated by reference into this Item 13.

Review, Approval or Ratification of Transactions with Related Persons

If a conflict or potential conflict of interest arises between our general partner and its affiliates (including the WPP Group and Pocahontas Royalties) on the one hand, and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under "—Conflicts of Interest."

Pursuant to our Code of Business Conduct and Ethics, conflicts of interest are prohibited as a matter of policy, except under guidelines approved by the Board of Directors and as provided in the Omnibus Agreement and our partnership agreement. For the year ended December 31, 2024 there were no transactions where such guidelines were not followed.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended, and we engaged Ernst & Young LLP to audit our accounts and assist with tax compliance for fiscal 2024 and 2023. All of our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board of Directors. The following table presents fees for professional services rendered by Ernst & Young LLP:

	2024		2023
Audit Fees (1)	$	1,002,500	$	972,500
Tax Fees (2)		455,000		442,270

⁽¹⁾ Audit fees include fees associated with the annual integrated audit of our consolidated financial statements and internal controls over financial reporting, separate audits of subsidiaries and reviews of our quarterly financial statement for inclusion in our Form 10-Q and comfort letters; consents; work related to acquisitions; assistance with and review of documents filed with the SEC.

⁽²⁾ Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1.

Audit and Non-Audit Services Pre-Approval Policy

I. Statement of Principles

Under the Sarbanes-Oxley Act of 2002 (the "Act"), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the SEC has issued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the "Policy"), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor may be pre-approved.

The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee ("general pre-approval") or require the specific pre-approval of the Audit Committee ("specific pre-approval"). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficient procedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-approval by the Audit Committee.

For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The Audit Committee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiarity with our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage or control risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative.

The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services.

The appendices to the Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any general pre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. For the audit, pre-approval is for the fiscal year as the time between approval and the actual issuance of the audit may be more than 12 months. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will add or subtract to the list of general pre-approved services from time to time, based on subsequent determinations.

The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by the independent auditor to management.

Ernst & Young LLP, our independent auditor reviews this Policy annually and it does not adversely affect its independence.

II. Delegation

As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Stephen P. Smith, the Chairman of the Audit Committee. Mr. Smith must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.

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III. Audit Services

The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annual financial statement audit (including required quarterly reviews), subsidiary audits and other procedures required to be performed by the independent auditor to be able to form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testing performed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services also include the attestation engagement for the independent auditor’s report on internal controls for financial reporting. The Audit Committee monitors the audit services engagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in audit scope, partnership structure or other items.

In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other audit services, which are those services that only the independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits for our subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection with securities offerings.

IV. Audit-related Services

Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financial statements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does not impair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accounting consultations related to accounting, financial reporting or disclosure matters not classified as "Audit Services"; assistance with understanding and implementing new accounting and financial reporting guidance from rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal control reporting requirements.

V. Tax Services

The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advice without impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes it may grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would not impair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of the independent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officer or outside counsel to determine that the tax planning and reporting positions are consistent with this Policy.

VI. Pre-Approval Fee Levels or Budgeted Amounts

Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Any proposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overall relationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determine the appropriate ratio between the total amount of fees for audit, audit-related and tax services.

VII. Procedures

All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submitted to the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of any such services rendered by the independent auditor.

Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the Audit Committee by both the independent auditor and the Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with the SEC’s rules on auditor independence.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) and (2) Financial Statements and Schedules

(1) See "Item 8. Financial Statements and Supplementary Data."

(2) All schedules are omitted because they are not required or because the information is immaterial or provided elsewhere in the Consolidated Financial Statements and Notes thereto.

(a)(3) Sisecam Wyoming LLC Financial Statements

The financial statements of Sisecam Wyoming LLC required pursuant to Rule 3-09 of Regulation S-X are included in this filing as Exhibit 99.1.

(a)(4) Exhibits

Exhibit Number	Description
3.1	Fifth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of March 2, 2017 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on March 6, 2017).
3.2	Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on December 16, 2011).
3.3	Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of October 31, 2013 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on October 31, 2013).
3.4	Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of Annual Report on Form 10-K for the year ended December 31, 2002).
3.5	Certificate of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 filed April 19, 2002, File No. 333-86582).
4.1	Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed June 23, 2003).
4.2	First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on July 20, 2005).
4.3	Second Amendment, dated as of March 28, 2007, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 29, 2007).
4.4	First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on July 20, 2005).
4.5	Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 29, 2007).
4.6	Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 26, 2009).
4.7	Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April 21, 2011).
4.8	Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to Current Report on Form 8-K filed June 23, 2003).
4.9	Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed June 23, 2003).
4.10	Form of Series D Note (incorporated by reference to Exhibit 4.12 to Annual Report on Form 10-K filed February 28, 2007).

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Exhibit Number	Description
4.11	Form of Series E Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed March 29, 2007).
4.12	Form of Series F Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 7, 2009).
4.13	Form of Series G Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 7, 2009).
4.14	Form of Series H Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 5, 2011).
4.15	Form of Series I Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 5, 2011).
4.16	Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 15, 2011).
4.17	Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on October 3, 2011).
4.18	Registration Rights Agreement, dated as of January 23, 2013, by and among Natural Resource Partners L.P. and the Investors named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on January 25, 2013).
4.19	Third Amendment, dated as of June 16, 2015, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 18, 2015).
4.20	Fourth Amendment, dated as of September 9, 2016, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 12, 2016).
4.21	Indenture, dated April 29, 2019, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as issuers, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 2, 2019).
4.22	Form of 9.125% Senior Notes due 2025 (contained in Exhibit 1 to Exhibit 4.21).
4.23	Registration Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 6, 2017).
4.24	Form of Warrant to Purchase Common Units (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 6, 2017).
4.25	Description of Equity Securities of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.25 to Annual Report on Form 10-K filed on February 27, 2020).
10.1	Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 18, 2015).
10.2	First Amendment, dated as of June 3, 2016, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 7, 2016).
10.3	First Amended and Restated Omnibus Agreement, dated as of April 22, 2009, by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed May 7, 2009).
10.4	Limited Liability Company Agreement of Sisecam Wyoming LLC, dated June 30, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed by Sisecam Resources LP on July 2, 2014).
10.5	Amendment No. 1 to the Limited Liability Company Agreement of Sisecam Wyoming LLC dated November 5, 2015 (incorporated by reference to Exhibit 10.22 to Annual Report on Form 10-K filed by Sisecam Resources LP on March 11, 2016).

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Exhibit Number	Description
10.6	Second Amendment, dated as of March 2, 2017, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed on March 6, 2017).
10.7	Fourth Amendment, dated as of April 3, 2019, to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on April 9, 2019).
10.8	Master Assignment Agreement and Fifth Amendment to Third Amended Credit Agreement, dated as of August 9, 2022 by and among NRP (Operating) LLC, the Lenders party thereto, the Exiting Lenders, and Zions Bancorporation, N.A. dba Amegy Bank, as administrative agent for the Lenders, as Swingline Lender, and as an Issuing Bank (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 11, 2022).
10.9	Sixth Amendment to the Third Amended and Restated Credit Agreement, dated as of May 11, 2023, by and among NRP (Operating) LLC, the lenders party thereto and Zions Bancorporation, N.A. dba Amegy Bank, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on May 15, 2023).
10.10	New Lender Agreement, dated as of May 11, 2023, by and among NRP (Operating) LLC, Zions Bancorporation, N.A. dba Amegy Bank, and Gulf Capital Bank (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on May 15, 2023).
10.11	New Lender Agreement, dated as of February 1, 2024, by and among NRP (Operating) LLC, Zions Bancorporation, N.A. dba Amegy Bank, and Summit Community Bank (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on February 6, 2024).
10.12	Commitment Increase Agreement dated as of February 14, 2024, by and among NRP (Operating) LLC, Zions Bancorporation, N.A. dba Amegy Bank, and Frost Bank (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on February 20, 2024).
10.13	New Lender Agreement, dated as of September 1, 2022 by and among NRP (Operating) LLC, the Borrower, Zions Bancorporation, N.A. dba Amegy Bank, in its capacity as administrative agent under the Fifth Amendment to Third Amended Credit Agreement and Prosperity Bank, the New Lender (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 8, 2022).
10.14	New Lender Agreement, dated as of April 8, 2019, by and among NRP (Operating) LLC and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on April 9, 2019).
10.15	Master Amendment and Supplement to Coal Mining and Transportation Lease Agreements and Parent Guaranty dated June 30, 2020 by and among NRP (Operating) LLC, WPP LLC, Hod LLC, Independence Land Company, LLC, Williamson Transport LLC, Foresight Energy LP, Foresight Energy GP LLC, Foresight Energy LLC, Macoupin Energy, LLC, Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC, Foresight Energy Resources LLC, and Foresight Energy Operating LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on July 1, 2020).
10.16	Limited Waiver dated February 28, 2020 by Natural Resource Partners L.P., GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 3, 2020).
10.17	Right of First Offer Agreement dated as of February 28, 2020 by and among Pocahontas Royalties LLC, Natural Resource Partners L.P., GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC. (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March 3, 2020).
10.18+	Natural Resource Partners L.P. 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January 17, 2018).
10.19+	Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-8 filed on February 9, 2018).
10.20+	Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 filed on February 9, 2018).
10.21+	Form of Phantom Unit Award Agreement (Employees and Service Providers) (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K filed on February 27, 2020).
10.22+	Form of Phantom Form of Phantom Unit Award Agreement (Directors) (incorporated by reference to Exhibit 10.14 to Annual Report on Form 10-K filed on February 27, 2020).
10.23+	Form of Phantom Unit Award Agreement (Directors with Deferral Election) (incorporated by reference to Exhibit 10.15 to Annual Report on Form 10-K filed on February 27, 2020).
10.24	Seventh Amendment to the Third Amended and Restated Credit Agreement, dated as of October 15, 2024, by and among NRP (Operating) LLC, the lenders party thereto and Zions Bancorporation, N.A. dba Amegy Bank, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on October 17, 2024).
19.1*	Natural Resource Partners L.P. Insider Trading Policy
21.1*	List of Subsidiaries of Natural Resource Partners L.P.
23.1*	Consent of Ernst & Young LLP.
23.2*	Consent of PricewaterhouseCoopers LLP.
23.3*	Consent of BDO USA, P.C.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1**	Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2**	Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
96.1*	S-K 1300 Technical Report Summary on the Big Island Mine, Sweetwater County, Wyoming, USA, dated February 27, 2025.
97.1*	Natural Resource Partners L.P. Incentive-Based Compensation Recoupment Policy, dated August 2, 2023 (incorporated by reference to Exhibit 97.1 to Annual Report on Form 10-K filed on March 7, 2024).
99.1*	Financial Statements of Sisecam Wyoming LLC as of December 31, 2024 and 2023 and for the years ended December 31, 2024, 2023 and 2022.

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Exhibit Number	Description
101.INS*	Inline XBRL Instance Document
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101)
*	Filed herewith
**	Furnished herewith
+	Management compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NATURAL RESOURCE PARTNERS L.P.
	By:	NRP (GP) LP, its general partner
	By:	GP NATURAL RESOURCE
		PARTNERS LLC, its general partner
Date: February 28, 2025
	By:	/s/     CORBIN J. ROBERTSON, JR.
		Corbin J. Robertson, Jr.
		Chairman of the Board, Director and
		Chief Executive Officer
		(Principal Executive Officer)
Date: February 28, 2025
	By:	/s/     CHRISTOPHER J. ZOLAS
		Christopher J. Zolas
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: February 28, 2025
	/s/     GALDINO J. CLARO
	Galdino J. Claro
	Director
Date: February 28, 2025
	/s/     PAUL B. MURPHY, JR.
	Paul B. Murphy, Jr.
	Director
Date: February 28, 2025
	/s/     RICHARD A. NAVARRE
	Richard A. Navarre
	Director
Date: February 28, 2025
	/s/     CORBIN J. ROBERTSON III
	Corbin J. Robertson III
	Director
Date: February 28, 2025
	/s/     STEPHEN P. SMITH
	Stephen P. Smith
	Director
Date: February 28, 2025
	/s/     LEO A. VECELLIO, JR.
	Leo A. Vecellio, Jr.
	Director

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