nrp-20211231

Statements included in this 10-K may constitute forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding: the effects of the global COVID-19 pandemic; our business strategy; our liquidity and access to capital and financing sources; our financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projected production levels by our lessees; Sisecam Wyoming LLC’s ("Sisecam Wyoming's"), formerly known as Ciner Wyoming, trona mining and soda ash refinery operations; distributions from our soda ash joint venture; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and global and U.S. economic conditions.

These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should not put undue reliance on any forward-looking statements. See "Item 1A. Risk Factors" in this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to differ.

As used in this Part I, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes due 2025 (the "2025 Senior Notes").

Our operations are conducted through Opco and our operating assets are owned by our subsidiaries. NRP (GP) LP, our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations and the Board of Directors and officers of GP Natural Resource Partners LLC make decisions on our behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Subject to the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with Blackstone Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree"), Mr. Robertson, Jr. is entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC and has delegated the right to appoint one director to Blackstone.

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.

Under our standard royalty lease, we grant the operators the right to mine and sell our coal in exchange for royalty payments based on the greater of a percentage of the sale price or fixed royalty per ton of minerals mined and sold. Lessees calculate royalty payments due to us and are required to report tons of minerals mined and sold as well as the sales prices of the extracted minerals. Therefore, to a great extent, amounts reported as royalty revenues are based upon the reports of our lessees. We periodically audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify that the information that our lessees have submitted to us is accurate. Our audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to us and the actual results from each property.

Because we do not operate any coal mines, our coal 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 has adopted new rules to modernize the property disclosure requirements for registrants with significant mining activities, which we have to comply with in this Annual Report on Form 10-K. The new 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 new rules, and we are not able to obtain such information without unreasonable burden or expense. The new rules require that reserve estimates be based on and disclosures include technical reports prepared using extensive mine-specific geological and engineering data, as well as market and cost assumptions that we as a mineral owner do not have, include, but are 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 new rules. As a result, we are relying on the royalty company exceptions and have ceased to report coal and other hard mineral reserves in this Annual Report on Form 10-K.

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, sometimes referred to as steam coal, is used in the production of electricity. The amount of thermal coal produced in the United States has been steadily falling over the last decade as energy providers shift from coal-fired plants to natural gas-fired facilities, and to a lesser extent, alternative energy sources such as geothermal, wind and solar. We believe the long-term secular decline experienced by thermal coal over the last decade will continue. That fact, combined with the long-term strength of our metallurgical business and the carbon neutral initiatives we discuss below, will result in thermal coal becoming a diminishing contributor to NRP in years to come. The vast majority of our thermal sales are located in Illinois and its operations are some of the most cost-efficient mines east of the Mississippi River. The remainder of our thermal coal is located in Montana and Appalachia.

Region

Property/Lease Name

Operator(s)

Coal Type

2021 Sales Volumes (Millions of Tons)

Appalachia Basin

Northern

Carter Roag

Metinvest

Met

0.5

Central

Alpha-CAPP (VA)

Alpha Metallurgical Resources Inc.

Met

3.9

Central

Elk Creek

Ramaco Royalty Company, LLC

Met

1.7

Central

Coal Mountain

ECP

Met

1.2

Central

Kepler

Alpha Metallurgical Resources Inc.

Met

1.1

Southern

Oak Grove

Hatfield Metallurgical Coal Holdings, LLC

Met

1.5

Illinois Basin

Williamson

Foresight Energy Resources LLC

Thermal

5.7

Illinois Basin

Hillsboro

Foresight Energy Resources LLC

Thermal

3.7

Northern Powder River Basin

Western Energy

Rosebud Mining, LLC

Thermal

3.2

Alpha-CAPP (VA). The Alpha-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2021, approximately 3.9 million tons were sold from this property, substantially all of which was 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 in 2023 and Alpha will have the option to renew the lease upon the expiration of its current term. We receive payments based on the greater of a percentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject to minimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are credited against future royalties that are earned as minerals are produced and the lessee is time limited on the period available for recouping minimum payments. Production comes from underground room and pillar and surface mines and is trucked to one of two preparation plants. Coal is shipped via the CSX and Norfolk Southern railroads to utility and metallurgical customers. The book value of this property was $45.6 million at December 31, 2021.

Oak Grove. The Oak Grove property is located in Jefferson County, Alabama. In 2021, approximately 1.5 million tons of metallurgical coal were sold from this property. We currently lease this property to a subsidiary of Hatfield Metallurgical Coal Holdings, LLC ("Hatfield Metallurgical"). Previous operators of this property were Murray Metallurgical Coal Holdings LLC, Mission Coal, LLC, and Seneca Resources, LLC. The current lease with Hatfield Metallurgical expires in 2024 and Hatfield Metallurgical will have the option to renew the lease upon the expiration of its current term. 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 a longwall mine and is transported by beltline to a preparation plant. Metallurgical products are then shipped via railroad and barge to both domestic and export customers. The book value of this property was $5.3 million at December 31, 2021.

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 Williamson Energy will have the option to renew the leases upon the expiration of their current terms. 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. In 2021, approximately 5.7 million tons of thermal coal were sold from this property. 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 $45.3 million at December 31, 2021.

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 Hillsboro Energy will have the option to renew the lease upon the expiration of its current term. 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. In 2021, approximately 3.7 million tons of thermal coal were sold from this property. Production comes from a longwall mine. Coal is shipped by rail via either the Union Pacific, Norfolk Southern or Canadian National railroads, or by barges to domestic utilities customers. The book value of this property was $224.6 million at December 31, 2021.

Production at the Foresight Macoupin mine was temporarily ceased in March 2020. Pursuant to the Master Agreement, Foresight is no longer obligated to make royalty, transportation fee, or quarterly minimum payments to us under the Macoupin coal mining lease and transportation agreements. Foresight will pay an annual Macoupin fee of $2.0 million to NRP each year through 2023. The amounts paid for 2021 are included in the fixed amounts discussed in the paragraph above. Foresight also forfeited its right to recoup all previously paid but unrecouped minimum payments with respect to the Macoupin mine. At all times that the Macoupin mine remains in temporary cessation of production, Foresight will take reasonable actions to preserve, protect, and store the equipment, infrastructure, and property located at the mine.

Beginning January 1, 2024, we may at any time elect to cause Foresight to transfer the Macoupin mine and all associated equipment and permits to us for no consideration. If we make this election, we will assume all liabilities associated with the Macoupin mine. Also beginning January 1, 2024, Foresight may at any time elect to offer to sell the Macoupin assets to us for $1.00. If we accept Foresight’s offer, we will assume all liabilities associated with the Macoupin mine. If we do not accept Foresight’s offer, Foresight may proceed to permanently seal the Macoupin mine and conduct all reclamation activities. To the extent the elections described above are not made, Foresight will continue to pay the annual $2.0 million fee to NRP each year that the mine remains in temporary cessation of production. In addition, Foresight may determine at any time to recommence operations at the Macoupin mine, at which time we and Foresight will negotiate in good faith to enter into new coal mining lease and transportation agreements.

We own transportation and processing infrastructure related to certain of our coal properties, including loadout and other transportation assets at Foresight's Williamson and Macoupin mines in the Illinois Basin, for which we collect throughput fees or rents. We lease our Macoupin and Williamson transportation and processing infrastructure to subsidiaries 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 and Macoupin mines, 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 $9.1 million in revenue related to our coal transportation and processing assets during the year ended December 31, 2021. Production at the Macoupin mine was temporarily ceased in March 2020 and in June 2020, we and Foresight entered into a Master Agreement in connection with Foresight’s emergence from bankruptcy as discussed above.

Our oil and gas properties are predominately located in Louisiana. Our various industrial mineral and construction aggregates properties are located across the United States and include minerals such as limestone, frac sand, lithium, copper, lead and zinc. We lease a portion of these minerals to third parties in exchange for royalty payments. The structure of these leases is similar to our coal leases, and these leases typically require minimum rental payments in addition to royalties. During 2021, we received $1.9 million in aggregates royalty revenues, including overriding royalty revenues. We also own forest assets, primarily in West Virginia, which generate revenues from the forestland through carbon offset credits and timber sales.

Carbon Sequestration. We own approximately 3.5 million acres of specifically reserved subsurface rights in the southern United States with the potential for permanent sequestration of greenhouse gases. The carbon capture utilization and storage industry (“CCUS”) is in its infancy and the future is highly uncertain, but a few facts are clear. A sequestration project requires acreage possessing unique geologic characteristics, close proximity to sources of industrial-scale greenhouse gas emissions, and the appropriate form of legal title that grants the acreage owner the right to sequester emissions in the subsurface. While carbon sequestration rights and ownership continue to evolve, we believe we own one of the largest inventory of acreage with potential for carbon sequestration activities in the United States.

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. With regards to wind and solar energy opportunities, we are actively engaged in discussions for potential use of its acreage for these types of renewable energy developments predominately in Kentucky and West Virginia.

We own a 49% non-controlling equity interest in Sisecam Wyoming. Sisecam Resources LP, (formerly know as Ciner Resources LP) our operating partner ("Sisecam Resources"), controls and operates Sisecam Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries. Sisecam Resources is a publicly traded master limited partnership that depends on distributions from Sisecam Wyoming in order to make distributions to its public unitholders. As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine or soda ash production plant. We appoint three of the seven members of the Board of Managers of Sisecam Wyoming and have certain limited negative controls relating to the company. We have limited approval rights with respect to Sisecam Wyoming, and our partner controls most business decisions, including decisions with respect to distributions and capital expenditures. 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. In 2021, as soda ash markets improved, Sisecam Wyoming resumed distributions with respect to the third quarter; however, distributions may again be suspended in the future.

In December 2021, Sisecam Resources, the owner of the remaining 51% of our soda ash business was subject to a change in control. Prior to the transaction, Sisecam Wyoming was referred to as Ciner Wyoming and Sisecam Resources was referred to as Ciner Resources L.P. Upon closing of the transaction, Ciner Enterprises Inc., the indirect owner of approximately 74% of the partnership units of Ciner Resources L.P., sold 60% of its interest in Ciner Resources Corporation, the parent company of Ciner Resources L.P., to Sisecam Chemicals USA Inc. (“Sisecam USA”), an indirect subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş. Ciner Resources Corporation subsequently changed its name to Sisecam Chemical Resources LLC and Ciner Resources L.P. changed its name to Sisecam Resources L.P. Following the transaction, we continue to have the right to appoint three of the seven Board of Managers of Sisecam Wyoming. Sisecam USA has the right to direct the appointment of three and Ciner Enterprises has the right to direct the appointment of one of the four members of the Sisecam Wyoming Board of Managers that are allocated to Sisecam Resources.

Sisecam Wyoming is one of the largest and lowest cost producers of soda ash in the world, serving a global market from its facility located in the Green River Basin of Wyoming. The Green River Basin geological formation holds the largest, and one of the highest purity, known deposits of trona ore in the world. Trona, a naturally occurring soft mineral, is also known as sodium sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. Sisecam Wyoming processes trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other consumer and industrial products. The vast majority of the world’s accessible trona is located in the Green River Basin. According to historical production statistics, approximately 30% of global soda ash is produced by processing trona, with the remainder being produced synthetically through chemical processes. The costs associated with procuring the materials needed for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-based production consumes less energy and produces fewer undesirable by-products than synthetic production.

In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering liquor, a solution consisting of sodium carbonate dissolved in water. Sisecam Wyoming then adds activated carbon to filters to remove organic impurities, which can cause color contamination in the final product. The resulting clear liquid is then crystallized in evaporators, producing sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge to remove excess water. The resulting material is dried in a product dryer to form anhydrous sodium carbonate, or soda ash. The resulting processed soda ash is then stored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. Sisecam Wyoming’s storage silos can hold over 58,000 short tons of processed soda ash at any given time. The facility is in good working condition and has been in service for more than 50 years.

Deca Rehydration. The evaporation stage of trona ore processing produces a precipitate and natural by-product called deca. "Deca," short for sodium carbonate decahydrate, is one part soda ash and ten parts water. Solar evaporation causes deca to crystallize and precipitate to the bottom of the four main surface ponds at the Green River Basin facility. The deca rehydration process enables Sisecam Wyoming to recover soda ash from the deca-rich purged liquor as a by-product of the refining process. The soda ash contained in deca is captured by allowing the deca crystals to evaporate in the sun and separating the dehydrated crystals from the soda ash. The separated deca crystals are then blended with partially processed trona ore in the dissolving stage of the production process. This process enables Sisecam Wyoming to reduce waste storage needs and convert what is typically a waste product into a usable raw material. Sisecam Wyoming anticipates that its current deca stockpiles will be exhausted by 2024 and that production rates will decline approximately 200,000 short tons per year if that production capacity is not replaced.

Shipping and Logistics. All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended December 31, 2021, 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. For the year ended December 31, 2021, Sisecam Wyoming assisted the majority of its domestic customers in arranging their freight services. During 2021, Sisecam Wyoming had no shortfall payments and does not expect to make any such payments in the future. A leased fleet of more than 2,200 hopper cars serve as dedicated modes of shipment to Sisecam Wyoming's domestic and international customers. For non ANSAC exports, soda ash is shipped on unit trains primarily to Longview, Washington for bulk shipments. For the year ended December 31, 2021, ANSAC provided logistics and support services for a portion of the export sales primarily out of Portland, Oregon and Longview, Washington. From these ports, soda ash is loaded onto ships for delivery to ports all over the world. For domestic sales, Sisecam Chemical Resources LLC ("Sisecam Chemical Resources") provides similar services. Sisecam Chemical Resources is the parent company of the sole member of the general partner of our operating partner, Sisecam Resources. Sisecam Chemical Resources is owned 60% by Sisecam USA and 40% by Ciner Enterprises Inc.

For customers in North America, Sisecam Chemical Resources 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. In 2021, Sisecam Wyoming had more than 70 domestic customers and has had long-term relationships with the majority of its customers.

Historically, by design and prior to Sisecam Chemical Resources’ exit from ANSAC, ANSAC managed most of Sisecam Wyoming's international sales, marketing and logistics, and as a result, was its largest customer for the years ended December 31, 2020 and 2019, accounting for 45% and 60%, respectively, of its net sales. ANSAC takes soda ash orders directly from its overseas customers and then purchases soda ash for resale from its member companies pro rata based on each member’s allocated volumes. ANSAC is the exclusive distributor for its members to the markets it serves. The ANSAC exit allowed Sisecam Chemical Resources to improve access to customers and gain control over placement of its sales in the international marketplace in 2021. This enhanced view of the global market allows Sisecam Chemical Resources to better understand supply/demand fundamentals thus allowing better decision making for its business. Sisecam Chemical Resources continues to optimize its distribution network leveraging strengths of existing distribution partners while expanding as the business requires in certain target areas.

Leases and License. Sisecam Wyoming is party to several mining leases and one license for its subsurface mining rights. Some of the leases are renewable at Sisecam Wyoming’s option upon expiration. Sisecam Wyoming pays royalties to the State of Wyoming, the U.S. Bureau of Land Management and Sweetwater Royalties LLC, a subsidiary of Sweetwater Trona OpCo LLC and the successor in interest to the license with the Rock Springs Royalty Company LLC, an affiliate of Occidental Petroleum Corporation (formerly Anadarko Petroleum Corporation), The royalties are calculated based upon a percentage of the value of soda ash and related products sold at a certain stage in the mining process. These royalty payments may be subject to a minimum domestic production volume from the Green River Basin facility. Sisecam Wyoming is also obligated to pay annual rentals to its lessors and licensor regardless of actual sales. In addition, Sisecam Wyoming pays a production tax to Sweetwater County, and trona severance tax to the State of Wyoming that is calculated based on a formula that utilizes the volume of trona ore mined and the value of the soda ash produced. Sisecam Wyoming has a perpetual right to continue operating under these leases and license as long as it maintains continuous mining operations and intends to continue renewing the leases and license as has been historical practice.

Expansion Project. Sisecam Wyoming has announced a significant capacity expansion capital project that could increase production levels to up to 3.5 million tons of soda ash per year. Sisecam Wyoming has conducted the initial basic design and is pursuing the related permits and detailed cost analysis pursuant to the basic design. As a result of current market conditions (in part related to the COVID-19 pandemic), Sisecam Wyoming is currently evaluating when and whether to pursue this project, as it will require significant capital expenditures. The costs of the expansion project could be higher than expected, or the execution of the project could be substantially delayed, which could materially impact Sisecam Wyoming’s profitability and result in a further delay of Sisecam Wyoming’s resumption of cash distributions to its members.

We have a significant concentration of revenues with Foresight and its subsidiaries, with total revenues of $37.4 million in 2021 from all of their mining operations, including transportation and processing services revenues, coal overriding royalty revenues and wheelage revenues. In June 2020, we entered into lease amendments with Foresight pursuant to which Foresight agreed to pay us fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreements between us and Foresight for calendar years 2020 and 2021. We also have a significant concentration of revenues from Alpha, with total revenues of $49.4 million in 2021 from several different mining operations, including wheelage revenues. For additional information on significant customers, refer to "Item 8. Financial Statements and Supplementary Data—Note 14. Major Customers."

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

We owned substantially all of our coal and aggregates mineral rights in fee as of December 31, 2021. 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.

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.

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 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 nitrogen oxide from power plants in twelve states. 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.

In August 2015, EPA published its final Clean Power Plan ("CPP") Rule, a multi-factor plan designed to cut carbon pollution from existing power plants, including coal-fired power plants. The rule required improving the heat rate of existing coal-fired power plants and substituting lower carbon-emission sources like natural gas and renewables in place of coal. As promulgated, the rule would force many existing coal-fired power plants to incur substantial costs in order to comply or alternatively result in the closure of some of these plants, likely resulting in a material adverse effect on the demand for coal by electric power generators. The rule was being challenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit. In February 2016, the Supreme Court of the United States stayed the CPP Rule pending a decision by the District of Columbia Circuit as well as any subsequent review by the Supreme Court. In April 2017, the United States Court of Appeals for the District of Columbia Circuit granted EPA’s motion to hold the litigation in abeyance. In December 2017, EPA issued a proposed rule repealing the CPP Rule and issued an Advance Notice of Proposed Rulemaking soliciting information regarding a potential replacement rule to the CPP Rule. In August 2018, EPA formally proposed the Affordable Clean Energy ("ACE") Rule, which would replace the CPP Rule. The ACE Rule contemplates a narrower approach than the CPP Rule, focusing on efficiency improvements at existing power plants and eliminating the CPP Rule’s broader goals that envisioned switches to non-fossil fuel energy sources and the implementation of efficiency measures on demand-side entities, which the EPA now considers beyond the reach of its authority under the Clean Air Act. The ACE Rule would also omit specific numerical emissions targets that had been established under the CPP Rule. The ACE Rule went into effect on September 6, 2019. As a result, the United States Court of Appeals for the District of Columbia Circuit dismissed the pending challenges to the CPP Rule as moot. The ACE Rule was challenged by public health groups, environmental groups, states, municipalities, industry groups, and power providers. The legal challenges were consolidated as American Lung Assoc. v. EPA before the D.C. Circuit Court of Appeals. Dozens of parties and over 170 amici filed briefs on the merits, and oral argument was held before a three-judge panel in October 2020. In January 2021, the D.C. Circuit issued a written opinion holding that the ACE Rule was based on EPA’s “erroneous legal premise” that when it determines the “best system of emission reduction” for existing sources, the Clean Air Act mandates that EPA may only consider emission reduction measures that can be applied at and/or to a stationary source (often referred to as “inside-the-fence” measures). The Court vacated and remanded the rule to EPA for further consideration in light of its opinion, which will now occur under the Biden administration.

other parties in the United States Court of Appeals for the District of Columbia Circuit, but is not subject to a stay. In April 2017, the court granted EPA’s motion to hold the litigation in abeyance while EPA reviews the rule. In December 2018, EPA issued a proposed rule revising the best system of emission reduction (“BSER”) for newly constructed coal-fired electric generating units, among other changes, to replace the 2015 rule. In a status report filed with the Court on January 15, 2021, EPA requested that the case remain in abeyance until after the transition to the Biden administration. On March 17, 2021, in line with President Biden’s Executive Order 13990, EPA asked the D.C. Circuit to vacate and remand the “significant contribution” final rule. On April 5, 2021, the D.C. Circuit vacated and remanded the January 2021 final rule.

President Obama also announced an emission reduction agreement with China’s President Xi Jinping in November 2014. The United States pledged that by 2025 it would cut climate pollution by 26% to 28% from 2005 levels. China pledged it would reach its peak carbon dioxide emissions around 2030 or earlier, and increase its non-fossil fuel share of energy to around 20% by 2030. In December 2015, the United States was one of 196 countries that participated in the Paris Climate Conference, at which the participants agreed to limit their emissions in order to limit global warming to 2°C above pre-industrial levels, with an aspirational goal of 1.5°C. While there is no way to estimate the impact of these climate pledges and agreements, they could ultimately have an adverse effect on the demand for coal, both nationally and internationally, if implemented. In 2019, President Trump withdrew from the Paris Climate Agreement. On February 19, 2021, the United States officially rejoined the Paris Climate Agreement per President Biden’s order signed January 20.

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 to have 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.

Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water Act and analogous state laws and regulations create two permitting programs for mining operations. The National Pollutant Discharge Elimination System (NPDES) program under Section 402 of the statute is administered by the states or EPA and regulates the concentrations of pollutants in discharges of waste and storm water from a mine site. The Section 404 program is administered by the Army Corps of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise “waters of the United States.” The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and may include land features not commonly understood to be a stream or wetlands. The Clean Water Act and its regulations prohibit the unpermitted discharge of pollutants into such waters, including those from a spill or leak. Similarly, Section 404 also prohibits discharges of fill material and certain other activities in waters unless authorized by the issued permit. In June 2015, EPA issued a new rule defining the scope of “Waters of the United States” (WOTUS) that are subject to regulation. The 2015 WOTUS rule was challenged by a number of states and private parties in federal district and circuit courts. In December 2017, EPA and the Corps proposed a rule to repeal the 2015 WOTUS rule and implement the pre-2015 definition. The repeal of the 2015 WOTUS rule took effect in December 2019. In December 2018, EPA and the Corps issued a proposed rule again revising the definition of “Waters of the United States.” The new rule (the Navigable Waters Protection Rule) took effect in June 2020. In most of the pending legal challenges to the 2015 WOTUS rule, the petitioners filed amended complaints to include allegations challenging the 2020 rule. In addition, various industry groups, environmental groups, and states filed new legal challenges to the 2020 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the 2020 rule. In light of this order, agencies have reverted to interpreting WOTUS in line with the pre-2015 regulatory regime. In late November 2021, EPA proposed a rule to revise the definition yet again, this time to restore the pre-2015 definition, with updates to reflect recent Supreme Court decisions.

In 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.

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.

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.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for reclaiming the mined property upon the completion of mining operations. Our lessees have obtained or applied for permits to mine a majority of the coal that is currently planned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional coal planned to be mined over the following five years. However, given the imposition of new requirements in the permits in the form of policies and the increased oversight review that has been exercised by EPA, there are no assurances that they will not experience difficulty and delays in obtaining mining permits in the future. In addition, EPA has used its authority to create significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coal operators.

Our Internet address is www.nrplp.com. We make available free of charge on or through our Internet website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us.

Because distributions on the common units are dependent on the amount of cash we generate, distributions fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter depends on numerous factors, some of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits. The actual amount of cash we have to distribute each quarter is reduced by payments in respect of debt service and other contractual obligations, including distributions on the preferred units, fixed charges, maintenance capital expenditures, and reserves for future operating or capital needs that the board of directors may determine are appropriate. We have significant debt service obligations and obligations to pay cash distributions on our preferred units. To the extent our board of directors deems appropriate, it may determine to decrease the amount of the quarterly distribution on our common units or suspend or eliminate the distribution on our common units altogether. In addition, because our unitholders are required to pay income taxes on their respective shares of our taxable income, our unitholders may be required to pay taxes in excess of any future distributions we make. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities. See "—Tax Risks to Our Unitholders—Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities."

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations, including payment of distributions on the preferred units. If we do not have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money, or sell assets or raise equity at unattractive prices, including higher interest rates. We are required to make substantial principal repayments each year in connection with Opco’s senior notes, with approximately $40 million due thereunder during 2022. 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.

In July 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after late 2021. Opco’s revolving credit facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which provide that we will adopt a replacement rate that is broadly accepted by the syndicated loan market. We currently do not expect the transition from LIBOR to have a material impact on us. However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty establishing a replacement rate under Opco’s revolving credit facility. In the event that we do not determine a replacement rate for LIBOR, in certain circumstances, Eurodollar Loans under Opco’s revolving credit facility may be suspended and converted to ABR Loans, which could bear higher interest rates. If we are unable to negotiate replacement rates on favorable terms, it could adversely affect our business, financial condition and results of operations. For a description of the interest rate on borrowings under Opco’s revolving credit facility, see “Item 8. Financial Statements and Supplementary Data—Note 11. Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net., Net.”

The COVID-19 pandemic adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities and global trading markets. Coal markets faced substantial challenges prior to the pandemic, and widespread increases in unemployment and decreases in electricity and steel demand further reduced demand and prices for coal in 2020. In addition, demand for and prices of soda ash decreased in 2020, as global manufacturing slowed. Our board of directors determined to suspend cash distributions to our common unitholders with respect to the first quarter of 2020 in order to preserve liquidity due to uncertainties created by the pandemic. In addition, Sisecam Wyoming suspended cash distributions to its members in 2020 due to adverse effects of the pandemic on the global and domestic soda ash markets. Both companies have resumed distributions, however there remains a risk that distributions could be suspended in the future due to a resumption of pandemic uncertainties.

significant uncertainty. The full extent to which the COVID-19 pandemic will impact our results is not fully known and is evolving, and will depend on future developments, which are highly uncertain and cannot be predicted. These include the severity, duration and spread of COVID-19, the success of actions taken by governments and health organizations to combat the disease and treat its effects, including additional remedial legislation, the emergence of any new COVID-19 variants that may arise, the timing, availability, effectiveness and adoption rates of vaccines and treatments and the extent to which, and when, general economic and operating conditions recover. Accordingly, any resulting financial impact cannot be reasonably estimated at this time but such amounts may be material. To the extent our board of directors deems necessary, it may determine to suspend cash distributions in future quarters as a result of the pandemic.

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.

The market price of soda ash directly affects the profitability of Sisecam Wyoming’s soda ash production operations. If the market price for soda ash declines, Sisecam Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash has been volatile, and those markets are likely to remain volatile in the future. The prices Sisecam Wyoming receives for its soda ash depend on numerous factors beyond Sisecam Wyoming’s control, including the COVID-19 pandemic, worldwide and regional economic and political conditions impacting supply and demand. In addition, the impact of the Sisecam Chemical Resources' exit from ANSAC and Sisecam Wyoming’s transition to the utilization of Sisecam Group’s global distribution network for some of its export operations beginning 2021 could affect prices received for export sales. Glass manufacturers and other industrial customers drive most of the demand for soda ash, and these customers experience significant fluctuations in demand and production costs. Competition from increased use of glass substitutes, such as plastic and recycled glass, has had a negative effect on demand for soda ash. Substantial or extended declines in prices for soda ash could have a material adverse effect on Sisecam Wyoming’s ability to continue to make distributions to its members and on our results of operations.

Challenges in the coal mining industry have led to significant consolidation activity. We own significant interests in all of Foresight’s mining operations, which accounted for approximately 17% of our total revenues in 2021. We also own significant interests in several of Alpha's mining operations, which accounted for approximately 23% of our total revenues in 2021. 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.

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.

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.

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.”

Global climate issues continue to attract public and scientific attention. Numerous reports have engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In addition to government regulation of greenhouse gas and other air pollutant emissions, there have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels, such as coal. One example is the Net Zero Banking Alliance, a group of over 100 banks worldwide representing over 40% of global banking assets who are committed to aligning their investment portfolios with net zero emissions by 2050. The impact of such efforts may adversely affect our ability to raise capital. In addition, a number of insurance companies have taken action to limit coverage for companies in the coal industry, which could result in significant increases in our costs of insurance or in our inability to maintain insurance coverage at current levels.

The operations of our lessees and Sisecam Wyoming are subject to stringent health and safety standards under increasingly strict federal, state and local environmental, health and safety laws, including mine safety regulations and governmental enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our properties.

New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements, could further regulate or tax mining industries and may also require significant changes to operations, the incurrence of increased costs or the requirement to obtain new or different permits, any of which could decrease our revenues and have a material adverse effect on our financial condition or results of operations. Under SMCRA, our coal lessees have substantial reclamation obligations on properties where mining operations have been completed and are required to post performance bonds for their reclamation obligations. To the extent an operator is unable to satisfy its reclamation obligations or the performance bonds posted are not sufficient to cover those obligations, regulatory authorities or citizens groups could attempt to shift reclamation liability onto the ultimate landowner, which if successful, could have a material adverse effect on our financial condition.

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

We do not have control over the operations of Sisecam Wyoming. We have limited approval rights with respect to Sisecam Wyoming, and our partner controls most business decisions, including decisions with respect to distributions and capital expenditures. During 2020, Sisecam Wyoming suspended cash distributions to its members due to adverse developments in the soda ash market resulting from the COVID-19 pandemic. Distributions resumed in 2021 but no assurance can be made that additional suspensions will not occur in the future. In December 2021, the parent of the 51% owner of Sisecam Wyoming (formerly Ciner Wyoming) sold 60% of its interest to Sisecam Chemicals USA Inc., a wholly owned subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş. As a result of the transaction, we will continue to appoint three of the seven Board of Managers of Sisecam Wyoming, Sisecam USA will appoint three and Ciner Enterprises Inc. will appoint one. Any changes to the distribution policy or the capital expenditure plans approved by the newly constituted Board of Managers could adversely affect the future cash flows to NRP and the financial condition and results of operations of Sisecam Wyoming.

Although Sisecam Chemicals Resources’ membership in ANSAC terminated on December 31, 2020, Sisecam Chemical Resources and ANSAC reached an agreement that it would continue selling tons, at substantially lower volumes to ANSAC and partner therewith on limited logistics services for a limited period of time. ANSAC was Sisecam Wyoming’s largest customer for the years ended December 31, 2020 and 2019, accounting for approximately 45% and 60%, respectively, of its net sales. Without the ANSAC membership, there is no assurance that Sisecam Chemical Resources will be able to retain existing foreign customers or secure new foreign customers or the related logistics arrangements on favorable terms, if at all, after the ANSAC termination date, which could materially adversely impact Sisecam Wyoming’s business, results of operations and financial condition and limit its ability to make distributions to us.

In 2019, Sisecam Wyoming announced a significant capacity expansion capital project intended to increase production levels to up to 3.5 million tons of soda ash per year. As a result of current market conditions (in part related to the COVID-19 pandemic), Sisecam Wyoming is currently evaluating when and whether to pursue this project, as it will require significant capital expenditures. The costs of the expansion project could be higher than expected, or the execution of the project could be substantially delayed, which could materially impact Sisecam Wyoming’s profitability and result in another suspension of Sisecam Wyoming’s cash distributions to its members, which in turn could have a material adverse effect on us.

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, 2021, 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.

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.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding common units (including common units held by our general partner and its affiliates and including common units deemed to be held by the holders of the preferred units who vote along with the common unitholders on an as-converted basis). Because of their substantial ownership in us, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates and the holders of the preferred units.

Our general partner may cause us to issue an unlimited number of common units, without common unitholder approval (subject to applicable New York Stock Exchange ("NYSE") rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units (including additional preferred units) without common unitholder approval (subject to applicable NYSE rules). In addition, we may issue additional common units upon the exercise of the outstanding warrants held by Blackstone and GoldenTree. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

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.

In addition, a change of control would constitute an event of default under our debt agreements. During the continuance of an event of default under our debt agreements, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us and/or declare all amounts payable by us immediately due and payable. In addition, upon a change of control, the holders of the preferred units would have the right to require us to redeem the preferred units at the liquidation preference or convert all of their preferred units into common units. A change of control also may trigger payment obligations under various compensation arrangements with our officers.

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.

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.

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.

Any modification to the U.S. federal income tax laws and interpretation 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.

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.

For our unitholders subject to the passive loss rules, our current operations include portfolio activities (such as our coal and mineral royalty businesses) and passive activities (such as our soda ash business). Any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset (i) our portfolio income, including income related to our coal and mineral royalty businesses, (ii) a unitholder’s income from other passive activities or investments, including investments in other publicly traded partnerships, or (iii) a unitholder’s salary or active business income. Thus, our unitholders' share of our portfolio income may be subject to U.S. federal income tax, regardless of other losses they may receive from us.

We may engage in transactions to reduce our 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.

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.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under these rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment 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.

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.

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, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, 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, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. 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.

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.

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. The Treasury regulations and other guidance from the IRS provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023. Thereafter, the obligation to withhold on a transfer of interests in a publicly traded partnership that is effected through a broker, 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 generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

Because there are no specific rules governing the U.S. federal income tax consequences 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.

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.

As used in this Item 7, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes due 2025 (the "2025 Senior Notes").

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 asses our ability to make cash distributions and repay debt.

Free cash flow ("FCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables; less maintenance and expansion capital expenditures and cash flow used in acquisition costs classified as investing or financing activities. FCF is calculated before mandatory debt repayments. FCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. FCF may not be calculated the same for us as for other companies. FCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess our ability to make cash distributions and repay debt.

Cash flow cushion represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables; less maintenance and expansion capital expenditures, cash flow used in acquisition costs classified as investing or financing activities, one-time beneficial items, mandatory Opco debt repayments, preferred unit distributions and redemption of PIK units, common unit distributions and warrant cash settlements. Cash flow cushion is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Cash flow cushion is a supplemental liquidity measure used by our management to assess our ability to make or raise cash distributions to our common and preferred unitholders and our general partner and repay debt or redeem preferred units.

Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) from continuing operations 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.


	Operating Segments
(In thousands)	Mineral Rights		Soda Ash		Corporate and Financing		Total
Revenues and other income	$	194,493	$	21,871	$	—	$	216,364
Net income (loss) from continuing operations	$	143,412	$	21,702	$	(56,212)	$	108,902
Asset impairments	5,102		—		—		5,102
Net income (loss) from continuing operations excluding asset impairments	$	148,514	$	21,702	$	(56,212)	$	114,004
Adjusted EBITDA (1)	$	167,613	$	11,101	$	(17,360)	$	161,354

Cash flow provided by (used in) continuing operations
Operating activities	$	159,845	$	11,106	$	(49,147)	$	121,804
Investing activities	$	2,412	$	—	$	—	$	2,412
Financing activities	$	(1,132)	$	—	$	(87,354)	$	(88,486)
Distributable cash flow (1)	$	162,257	$	11,106	$	(49,147)	$	124,216
Free cash flow (1)	$	161,008	$	11,106	$	(49,147)	$	122,967
Cash flow cushion (1)	N/A		N/A		N/A		$	36,172

The indenture governing our 2025 parent company notes restricts us from paying more than one-half of the quarterly distribution on our preferred units in cash if our consolidated leverage ratio exceeds 3.75x. Accordingly, the Board of Directors of our general partner had declared a distribution on our preferred units to be paid one-half in kind through the issuance of additional preferred units (“PIK units”) in 2021 when our leverage ratio exceeded 3.75x. Our consolidated leverage ratio fell below 3.75x during the fourth quarter of 2021 to 2.7x at December 31, 2021, allowing us to fully redeem at par all 19,321 paid-in-kind preferred units for $19.6 million in cash in accordance with their terms and including accrued interest, and to continue to pay common unit distributions in the first quarter of 2022. Therefore, as of the date of this report, no paid-in-kind preferred units remain outstanding and $250 million of 12.0% Class A Convertible Preferred Units remain outstanding. While our leverage ratio is expected to stay below 3.75x for the foreseeable future, future distributions on our common and preferred units will be determined on a quarterly basis by the Board of Directors. The Board of Directors considers numerous factors each quarter in determining cash distributions, including profitability, cash flow, debt service obligations, market conditions and outlook, estimated unitholder income tax liability and the level of cash reserves that the Board determines is necessary for future operating and capital needs.

Metallurgical coal markets have rebounded significantly from the lows seen in 2020 to record high pricing and the outlook remains strong as steel demand driven by global economic recovery is more than offsetting challenges related to the COVID-19 pandemic. Domestic and export thermal coal markets have also significantly improved from the lows seen in 2020, however we did not have meaningful sensitivity to thermal coal price movements in 2021 since the substantial majority of our thermal cash flows were fixed pursuant to a contract with Foresight Energy Resources LLC ("Foresight") that went into effect as they emerged from bankruptcy in 2020. That contract expired at the end of 2021 and we began receiving traditional royalty payments in January 2022. While we may benefit from improved thermal coal demand and pricing in the near term, thermal coal markets still face the long-term challenges presented by competition from natural gas and the secular shift to renewable energy.

We continue to identify alternative revenue sources across our large portfolio of land, mineral and timber assets. The types of opportunities include the sequestration of carbon dioxide underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy. We executed our first carbon neutral project in the fourth quarter of 2021 through the sale of 1.1 million carbon offset credits which represents 1.1 million tonnes of carbon sequestered in approximately 39,000 acres of our forestland in West Virginia. In the first quarter of 2022, we were able to execute another such project through the previously announced partnership with Denbury which provides opportunity for development of a world-class subsurface CO2 sequestration hub on Alabama's Gulf Coast. The agreement provides Denbury with the exclusive rights to develop a subsurface CO2 sequestration site on approximately 75,000 acres of underground pore space controlled by us in Baldwin County, near Mobile, Alabama, with estimated CO2 storage potential of over 300 million metric tons.

We expect this 75,000-acre project, if developed, to be the first of what will potentially be numerous subsurface sequestration projects conducted on the approximately 3.5 million acres where we own the rights to sequester CO2 underground across the United States. Our ability to create value and provide important benefits to the environment through alternative revenue sources continues to expand through transactions such as these and we are pleased to be on the forefront of subsurface carbon sequestration. While the timing and likelihood of additional cash flows being realized from further activities is uncertain, we believe our large ownership footprint throughout the United States will provide additional opportunities to create value in this regard with minimal capital investment.

As a result of the soda ash segment's improved performance, Sisecam Wyoming reinstated regular quarterly cash distributions in the fourth quarter of 2021, which were previously suspended since the third quarter of 2020. Accordingly, we received a $7.4 million distribution in the fourth quarter of 2021. We also received a special distribution of $3.9 million in the first quarter of 2021, for $11.3 million in total distributions from Sisecam Wyoming in 2021 as compared to $14.2 million of regular quarterly distributions received in 2020. In addition, strong fourth quarter 2021 soda ash demand and pricing resulted in further improved operating results and we received a $13.2 million quarterly distribution with respect to these strong fourth quarter 2021 operating results in February 2022.


	For the Year Ended December 31,				Increase (Decrease)		Percentage Change
(In thousands, except per ton data)	2021		2020
Coal sales volumes (tons)
Appalachia
Northern	1,335		647		688		106	%
Central	12,279		10,111		2,168		21	%
Southern	1,571		889		682		77	%
Total Appalachia	15,185		11,647		3,538		30	%
Illinois Basin	9,388		3,381		6,007		178	%
Northern Powder River Basin	3,151		1,738		1,413		81	%
Gulf Coast	55		—		55		100	%
Total coal sales volumes	27,779		16,766		11,013		66	%

Coal royalty revenue per ton
Appalachia
Northern	$	6.51	$	2.36	$	4.15	176	%
Central	5.71		4.17		1.54		37	%
Southern	9.14		4.75		4.39		92	%

Illinois Basin	2.12		2.36		(0.24)		(10)	%
Northern Powder River Basin	3.54		3.50		0.04		1	%
Gulf Coast	0.60		—		0.60		100	%
Combined average coal royalty revenue per ton	4.47		3.70		0.77		21	%

Coal royalty revenues
Appalachia
Northern	$	8,691	$	1,526	$	7,165	470	%
Central	70,149		42,207		27,942		66	%
Southern	14,355		4,221		10,134		240	%
Total Appalachia	93,195		47,954		45,241		94	%
Illinois Basin	19,917		7,973		11,944		150	%
Northern Powder River Basin	11,151		6,086		5,065		83	%
Gulf Coast	33		—		33		100	%
Unadjusted coal royalty revenues	124,296		62,013		62,283		100	%
Coal royalty adjustment for minimum leases	(20,207)		(10,145)		(10,062)		(99)	%
Total coal royalty revenues	$	104,089	$	51,868	$	52,221	101	%

Other revenues
Production lease minimum revenues	$	14,269	$	21,749	$	(7,480)	(34)	%
Minimum lease straight-line revenues	20,564		16,796		3,768		22	%
Forest CO2 sequestration revenues	13,790		—		13,790		100	%
Wheelage revenues	10,065		7,025		3,040		43	%
Property tax revenues	6,028		5,786		242		4	%
Coal overriding royalty revenues	4,367		4,977		(610)		(12)	%
Lease amendment revenues	4,696		3,450		1,246		36	%

Aggregates royalty revenues	1,889		1,717		172		10	%
Oil and gas royalty revenues	4,506		5,816		(1,310)		(23)	%
Other revenues	933		982		(49)		(5)	%
Total other revenues	$	81,107	$	68,298	$	12,809	19	%
Royalty and other mineral rights	$	185,196	$	120,166	$	65,030	54	%
Transportation and processing services revenues	9,052		8,845		207		2	%

Gain on asset sales and disposals	245		581		(336)		(58)	%
Total Mineral Rights segment revenues and other income	$	194,493	$	129,592	$	64,901	50	%

Total operating expenses decreased by $115.6 million primarily due to a $130.8 million decrease in asset impairments. Asset impairments in 2021 primarily related to a lease termination while asset impairments in 2020 were due to weakened coal markets that resulted in termination of certain coal leases, changes to lessee mine plans resulting in permanent moves off certain of our coal properties and decreased oil and gas drilling activity which negatively impacted the outlook for NRP's frac sand properties. This decrease was partially offset by a $9.9 million increase in depreciation, depletion and amortization expense primarily as a result of increased production at certain Illinois Basin coal properties. The remaining cost increases primarily related to increased incentive compensation expense as a result of significantly improved Partnership operating results year-over-year and increased overriding royalty expense due to higher coal sales and royalty revenue in 2021.


	Operating Segments
For the Year Ended (In thousands)	Mineral Rights		Soda Ash		Corporate and Financing		Total
December 31, 2021
Net income (loss) from continuing operations	$	143,412	$	21,702	$	(56,212)	$	108,902
Less: equity earnings from unconsolidated investment	—		(21,871)		—		(21,871)

Add: total distributions from unconsolidated investment	—		11,270		—		11,270
Add: interest expense, net	24		—		38,852		38,876


Add: depreciation, depletion and amortization	19,075		—		—		19,075
Add: asset impairments	5,102		—		—		5,102
Adjusted EBITDA	$	167,613	$	11,101	$	(17,360)	$	161,354

December 31, 2020
Net income (loss) from continuing operations	$	(40,180)	$	10,543	$	(55,182)	$	(84,819)
Less: equity earnings from unconsolidated investment	—		(10,728)		—		(10,728)

Add: total distributions from unconsolidated investment	—		14,210		—		14,210
Add: interest expense, net	79		—		40,889		40,968


Add: depreciation, depletion and amortization	9,198		—		—		9,198
Add: asset impairments	135,885		—		—		135,885
Adjusted EBITDA	$	104,982	$	14,025	$	(14,293)	$	104,714

Adjusted EBITDA increased $56.6 million primarily due to a $62.6 million increase in Adjusted EBITDA within our Mineral Rights segment as a result of higher revenues and other income during the year ended December 31, 2021 as discussed above. This increase was partially offset by a $2.9 million decrease in Adjusted EBITDA within our Soda Ash segment as a result of lower cash distributions received from Sisecam Wyoming during the year ended December 31, 2021 as compared to the prior year and a $3.1 million decrease in Adjusted EBITDA within our Corporate and Financing segment as a result of increased general and administrative costs primarily due to increased incentive compensation as a result of significantly improved Partnership operating results year-over-year.


	Operating Segments
For the Year Ended (In thousands)	Mineral Rights		Soda Ash		Corporate and Financing		Total
December 31, 2021
Net cash provided by (used in) operating activities of continuing operations	$	159,845	$	11,106	$	(49,147)	$	121,804

Add: proceeds from asset sales and disposals	249		—		—		249

Add: return of long-term contract receivable	2,163		—		—		2,163


Distributable cash flow	$	162,257	$	11,106	$	(49,147)	$	124,216
Less: proceeds from asset sales and disposals	(249)		—		—		(249)


Less: acquisition costs	(1,000)		—		—		(1,000)
Free cash flow	$	161,008	$	11,106	$	(49,147)	$	122,967
Less: mandatory Opco debt repayments							(39,396)
Less: preferred unit distributions							(15,571)
Less: common unit distributions							(22,645)
Less: warrant cash settlement							(9,183)
Cash flow cushion							$	36,172


	Operating Segments
For the Year Ended (In thousands)	Mineral Rights		Soda Ash		Corporate and Financing		Total




















December 31, 2020
Net cash provided by (used in) operating activities of continuing operations	$	124,737	$	14,037	$	(51,206)	$	87,568

Add: proceeds from asset sales and disposals	623		—		—		623
Add: proceeds from sale of discontinued operations	—		—		—		(65)
Add: return of long-term contract receivable	2,122		—		—		2,122


Distributable cash flow	$	127,482	$	14,037	$	(51,206)	$	90,248
Less: proceeds from asset sales and disposals	(623)		—		—		(623)
Less: proceeds from sale of discontinued operations	—		—		—		65
Less: acquisition costs	(1,000)		—		—		(1,000)

Free cash flow	$	125,859	$	14,037	$	(51,206)	$	88,690
Less: mandatory Opco debt repayments							(46,176)
Less: preferred unit distributions							(26,363)
Less: common unit distributions							(16,890)
Cash flow cushion							$	(739)

Cash flows used in financing activities decreased $0.9 million, from $89.4 million in the year ended December 31, 2020 to $88.5 million in the year ended December 31, 2021 primarily due to a $10.8 million decrease in cash distributions to preferred unitholders as we paid one-half of our preferred unit distributions in kind through the issuance of 15.6 million preferred units in 2021. Additionally, debt repayments decreased $6.8 million in 2021 as one series of Opco Senior Notes was fully repaid during the year ended December 31, 2020. These decreases in cash flow used were partially offset by $9.2 million used to settle the exercise of certain of our warrants in 2021 in addition to a $5.8 million increase in distributions to common unitholders and the general partner as we suspended our common unit distribution in the second quarter of 2020.

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.

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.

Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A majority of our contract modifications pertain to our coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices or minimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within royalty and other mineral rights revenues on our Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognized prospectively in accordance with the above lease classification.

Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time. The current portion of deferred revenue relates to deferred revenue on minimum leases and lease amendment fees that are to be recognized as revenue on a straight-line basis over the next twelve months. The long-term portion of deferred revenue relates to deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-line basis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as royalty revenues from production leases over the next twelve months, we are unable to estimate the current portion of deferred revenue.

We account for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. Our 49% investment in Sisecam Wyoming is accounted for using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortized over its estimated useful life. The carrying value in Sisecam Wyoming is recognized in equity in unconsolidated investment on our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings of Sisecam Wyoming on the Consolidated Statements of Comprehensive Income (Loss). We decrease our investment for our proportional share of distributions received from Sisecam Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are considered returns on investment and classified as operating cash inflows unless the cumulative distributions received exceed our cumulative equity in earnings. The excess of cumulative distributions received over our cumulative equity in earnings are considered returns of investment and classified as investing cash inflows.

Mineral rights 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.

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.

We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 $276 million and $263 million as of December 31, 2021 and 2020, respectively, and the Partnership’s equity in the net income of Sisecam Wyoming is stated at $22 million in 2021, $11 million in 2020 and $47 million in 2019. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sisecam Wyoming, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

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.


Description of the Matter			At December 31, 2021, the Partnership’s mineral rights, net totaled a combined $438 million. As described in Note 2 to the consolidated financial statements, the Partnership evaluates its mineral rights for possible impairment whenever events or changes in circumstances indicate that the carrying amounts of the asset may not be recoverable (“triggering events”). Management evaluates various qualitative factors in determining whether or not events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Potential events or circumstances include but are not limited to reduction in economically recoverable reserves or production ceasing on a property for an extended period, and other relevant information received from the operators, which may include operational or legal information that indicates production from mineral interests will not likely occur or may be significantly reduced in the future. Auditing the Partnership’s impairment triggers assessment involved our subjective judgment because, in determining whether a triggering event occurred, significant uncertainty exists with judgments management utilizes regarding the likelihood of future production and the likelihood of potential contract renewals or modifications, which rely on reserve or other relevant information reported by the operators.
How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Partnership’s impairment assessment process. We tested controls over the Partnership’s process for identifying and evaluating potential triggers of impairment and related significant judgments. To test the Partnership’s impairment assessment, our audit procedures included, among others, making inquiries of management (including personnel in operations) to understand changes in business, and evaluating the significant judgments and operating data used in the Partnership’s assessment. Specifically, we corroborated reserve information to reserve studies when available. Additionally, we inspected the cancellation or significant modification of royalty-based lease contracts. We searched for and evaluated other publicly available information, such as legislative or regulatory changes and bankruptcy filings, that corroborates or contradicts management’s assessment.

We have audited the accompanying balance sheets of Sisecam Wyoming LLC (the "Company") as of December 31, 2021 and 2020, the related statements of operations and comprehensive income, members' equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes that are included in Exhibit 99.1 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

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.

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 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.

The Company is a subsidiary and investee within two different global group structures and agreements directly between the Company and affiliates, or indirectly between affiliates that the Company does not control, can have a significant impact on recorded amounts or disclosures in the Company's financial statements, including any commitments and contingencies between the Company and affiliates or, potentially, third parties. Performing audit procedures to evaluate the Company’s identification of upstream affiliate relationships, transactions, and commitments and contingencies originating outside of the Ciner Enterprises, Inc. group and the impact of such matters on the financial statements represents a critical audit matter because of the increased auditor judgment necessary to perform audit procedures related to these matters and evaluate the results of those procedures.


	December 31,
(In thousands, except unit data)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	135,520	$	99,790

Accounts receivable, net	24,538		12,322
Other current assets, net	2,723		5,080

Total current assets	$	162,781	$	117,192
Land	24,008		24,008

Mineral rights, net	437,697		460,373
Intangible assets, net	16,130		17,459
Equity in unconsolidated investment	276,004		262,514
Long-term contract receivable, net	31,371		33,264

Other long-term assets, net	5,832		7,067
Total assets	$	953,823	$	921,877
LIABILITIES AND CAPITAL
Current liabilities
Accounts payable	$	1,956	$	1,385
Accrued liabilities	10,297		7,733
Accrued interest	1,213		1,714
Current portion of deferred revenue	11,817		11,485
Current portion of long-term debt, net	39,102		39,055

Total current liabilities	$	64,385	$	61,372
Deferred revenue	50,045		50,069
Long-term debt, net	394,443		432,444
Other non-current liabilities	5,018		5,131
Total liabilities	$	513,891	$	549,016
Commitments and contingencies (see Note 15)
Class A Convertible Preferred Units (269,321 and 253,750 units issued and outstanding at December 31, 2021 and 2020, respectively, at $1,000 par value per unit; liquidation preference of $1,850 per unit at December 31, 2021 and $1,700 per unit per unit at December 31, 2020)	$	183,908	$	168,337
Partners’ capital
Common unitholders’ interest (12,351,306 and 12,261,199 units issued and outstanding at December 31, 2021 and 2020, respectively)	$	203,062	$	136,927
General partner’s interest	1,787		459
Warrant holders’ interest	47,964		66,816
Accumulated other comprehensive income	3,211		322


Total partners' capital	$	256,024	$	204,524
Total liabilities and partners' capital	$	953,823	$	921,877


	For the Year Ended December 31,
(In thousands, except per unit data)	2021		2020		2019
Revenues and other income
Royalty and other mineral rights	$	185,196	$	120,166	$	191,069
Transportation and processing services	9,052		8,845		19,279
Equity in earnings of Sisecam Wyoming	21,871		10,728		47,089

Gain on asset sales and disposals	245		581		6,498
Total revenues and other income	$	216,364	$	140,320	$	263,935

Operating expenses
Operating and maintenance expenses	$	27,049	$	24,795	$	32,738
Depreciation, depletion and amortization	19,075		9,198		14,932
General and administrative expenses	17,360		14,293		16,730
Asset impairments	5,102		135,885		148,214
Total operating expenses	$	68,586	$	184,171	$	212,614

Income (loss) from operations	$	147,778	$	(43,851)	$	51,321

Other expenses, net
Interest expense, net	$	(38,876)	$	(40,968)	$	(47,453)

Loss on extinguishment of debt	—		—		(29,282)

Total other expenses, net	$	(38,876)	$	(40,968)	$	(76,735)

Net income (loss) from continuing operations	$	108,902	$	(84,819)	$	(25,414)
Income from discontinued operations	—		—		956
Net income (loss)	$	108,902	$	(84,819)	$	(24,458)


Less: income attributable to preferred unitholders	(31,609)		(30,225)		(30,000)
Net income (loss) attributable to common unitholders and the general partner	$	77,293	$	(115,044)	$	(54,458)

Net income (loss) attributable to common unitholders	$	75,747	$	(112,743)	$	(53,369)
Net income (loss) attributable to the general partner	1,546		(2,301)		(1,089)

Income (loss) from continuing operations per common unit (see Note 6)
Basic	$	6.14	$	(9.20)	$	(4.43)
Diluted	4.81		(9.20)		(4.43)

Net income (loss) per common unit (see Note 6)
Basic	$	6.14	$	(9.20)	$	(4.35)
Diluted	4.81		(9.20)		(4.35)

Net income (loss)	$	108,902	$	(84,819)	$	(24,458)
Comprehensive income from unconsolidated investment and other	2,889		2,916		868
Comprehensive income (loss)	$	111,791	$	(81,903)	$	(23,590)


	Common Unitholders			General Partner		Warrant Holders		Accumulated Other Comprehensive Income (Loss)		Partners' Capital Excluding Non-Controlling Interest		Non-Controlling Interest		Total Capital

(In thousands)	Units	Amounts
Balance at December 31, 2018	12,249	$	355,113	$	5,014	$	66,816	$	(3,462)	$	423,481	$	(2,935)	$	420,546

Net loss (1)	—	(23,969)		(489)		—		—		(24,458)		—		(24,458)
Distributions to common unitholders and the general partner	—	(32,487)		(663)		—		—		(33,150)		—		(33,150)
Distributions to preferred unitholders	—	(29,400)		(600)		—		—		(30,000)		—		(30,000)
Issuance of unit-based awards	12	486		—		—		—		486		—		486
Unit-based awards amortization and vesting	—	1,804		—		—		—		1,804		—		1,804
Comprehensive income (loss) from unconsolidated investment and other	—	(76)		8		—		868		800		—		800
Balance at December 31, 2019	12,261	$	271,471	$	3,270	$	66,816	$	(2,594)	$	338,963	$	(2,935)	$	336,028
Cumulative effect of adoption of accounting standard	—	(3,833)		(78)		—		—		(3,911)		—		(3,911)
Net loss (2)	—	(83,123)		(1,696)		—		—		(84,819)		—		(84,819)
Distributions to common unitholders and the general partner	—	(16,552)		(338)		—		—		(16,890)		—		(16,890)
Distributions to preferred unitholders	—	(29,511)		(602)		—		—		(30,113)		—		(30,113)
Acquisition of non-controlling interest in BRP	—	(4,747)		(97)		—		—		(4,844)		2,935		(1,909)

Unit-based awards amortization and vesting	—	3,222		—		—		—		3,222		—		3,222
Comprehensive income from unconsolidated investment and other	—	—		—		—		2,916		2,916		—		2,916
Balance at December 31, 2020	12,261	$	136,927	$	459	$	66,816	$	322	$	204,524	$	—	$	204,524

Net income (3)	—	106,724		2,178		—		—		108,902		—		108,902
Distributions to common unitholders and the general partner	—	(22,192)		(453)		—		—		(22,645)		—		(22,645)
Distributions to preferred unitholders	—	(30,519)		(623)		—		—		(31,142)		—		(31,142)

Issuance of unit-based awards	90	—		—		—		—		—		—		—
Unit-based awards amortization and vesting	—	2,647		—		—		—		2,647		—		2,647
Capital contribution	—	—		32		—		—		32		—		32
Warrant settlement	—	9,475		194		(18,852)		—		(9,183)		—		(9,183)

Comprehensive income from unconsolidated investment and other	—	—		—		—		2,889		2,889		—		2,889
Balance at December 31, 2021	12,351	$	203,062	$	1,787	$	47,964	$	3,211	$	256,024	$	—	$	256,024

(1)Net loss 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 loss includes $30.2 million of income attributable to preferred unitholders that accumulated during the period, of which $29.6 million is allocated to the common unitholders and $0.6 million is allocated to the general partner. (3) Net income includes $31.6 million of income attributable to preferred unitholders that accumulated during the period, of which $31.0 million is allocated to the common unitholders and $0.6 million is allocated to the general partner.


	For the Year Ended December 31,
(In thousands)	2021		2020		2019
Cash flows from operating activities
Net income (loss)	$	108,902	$	(84,819)	$	(24,458)
Adjustments to reconcile net income (loss) to net cash provided by operating activities of continuing operations:
Depreciation, depletion and amortization	19,075		9,198		14,932
Distributions from unconsolidated investment	11,270		14,210		31,850
Equity earnings from unconsolidated investment	(21,871)		(10,728)		(47,089)
Gain on asset sales and disposals	(245)		(581)		(6,498)

Loss on extinguishment of debt	—		—		29,282
Income from discontinued operations	—		—		(956)
Asset impairments	5,102		135,885		148,214
Bad debt expense	2,572		4,001		7,462
Unit-based compensation expense	4,039		3,570		2,361
Amortization of debt issuance costs and other	2,265		1,323		3,687
Change in operating assets and liabilities:
Accounts receivable	(14,415)		12,853		(6,035)
Accounts payable	570		207		(1,234)
Accrued liabilities	3,020		(2,205)		(3,656)
Accrued interest	(501)		(602)		(12,029)
Deferred revenue	307		9,733		(732)
Other items, net	1,714		(4,477)		2,218
Net cash provided by operating activities of continuing operations	$	121,804	$	87,568	$	137,319
Net cash provided by (used in) operating activities of discontinued operations	—		1,706		(8)
Net cash provided by operating activities	$	121,804	$	89,274	$	137,311

Cash flows from investing activities

Proceeds from asset sales and disposals	$	249	$	623	$	6,500
Return of long-term contract receivable	2,163		2,122		1,743
Acquisition of non-controlling interest in BRP	—		(1,000)		—
Acquisition of mineral rights	—		—		(22)
Net cash provided by investing activities of continuing operations	$	2,412	$	1,745	$	8,221
Net cash used in investing activities of discontinued operations	—		(65)		(629)
Net cash provided by investing activities	$	2,412	$	1,680	$	7,592

Cash flows from financing activities

Debt borrowings	$	—	$	—	$	300,000
Debt repayments	(39,396)		(46,176)		(463,082)

Distributions to common unitholders and the general partner	(22,645)		(16,890)		(33,150)
Distributions to preferred unitholders	(15,571)		(26,363)		(30,000)
Warrant settlement	(9,183)		—		—
Acquisition of non-controlling interest in BRP	(1,000)		—		—
Contributions from (to) discontinued operations	—		1,641		(637)
Other items	(691)		—		(26,436)
Net cash used in financing activities of continuing operations	$	(88,486)	$	(87,788)	$	(253,305)
Net cash provided by (used in) financing activities of discontinued operations	—		(1,641)		637
Net cash used in financing activities	$	(88,486)	$	(89,429)	$	(252,668)

Net increase (decrease) in cash and cash equivalents	$	35,730	$	1,525	$	(107,765)

Cash and cash equivalents of continuing operations at beginning of period	99,790		98,265		206,030





Cash and cash equivalents at end of period	$	135,520	$	99,790	$	98,265


	For the Year Ended December 31,
(In thousands, except per unit data)	2021		2020		2019
Diluted income (loss) per common unit
Weighted average common units—basic	12,337		12,261		12,260
Plus: dilutive effect of preferred units	9,604		—		—
Plus: dilutive effect of warrants	74		—		—
Plus: dilutive effect of unvested unit-based awards	178		—		—
Weighted average common units—diluted	22,193		12,261		12,260

Net income (loss) from continuing operations	$	108,902	$	(84,819)	$	(25,414)

Less: income attributable to preferred unitholders	—		(30,225)		(30,000)
Diluted net income (loss) from continuing operations attributable to common unitholders and the general partner	$	108,902	$	(115,044)	$	(55,414)
Add (less): net loss (income) from continuing operations attributable to the general partner	(2,178)		2,301		1,108
Diluted net income (loss) from continuing operations attributable to common unitholders	$	106,724	$	(112,743)	$	(54,306)

Diluted net income from discontinued operations attributable to common unitholders	$	—	$	—	$	937

Net income (loss)	$	108,902	$	(84,819)	$	(24,458)

Less: income attributable to preferred unitholders	—		(30,225)		(30,000)
Diluted net income (loss) attributable to common unitholders and the general partner	$	108,902	$	(115,044)	$	(54,458)
Add (less): diluted net loss (income) attributable to the general partner	(2,178)		2,301		1,089
Diluted net income (loss) attributable to common unitholders	$	106,724	$	(112,743)	$	(53,369)

Diluted net income (loss) from continuing operations per common unit	$	4.81	$	(9.20)	$	(4.43)
Diluted net income from discontinued operations per common unit	$	—	$	—	$	0.08
Diluted net income (loss) per common unit	$	4.81	$	(9.20)	$	(4.35)

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, 2021. 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, 2021 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.

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, 2021 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, 2021, 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.

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.

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.

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. Subject to Board Representation and Observation Rights Agreement with Blackstone and GoldenTree, Mr. Robertson is entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to appoint one director to Blackstone.

Name

Age

Position with the General Partner

Corbin J. Robertson, Jr.

Chairman of the Board and Chief Executive Officer

Craig W. Nunez

President and Chief Operating Officer

Christopher J. Zolas

Chief Financial Officer and Treasurer

Kevin J. Craig

Executive Vice President

Philip T. Warman

General Counsel and Secretary

Gregory F. Wooten

Senior Vice President, Chief Engineer

Galdino J. Claro

Director

Alexander D. Greene

Director

S. Reed Morian

Director

Paul B. Murphy, Jr.

Director

Richard A. Navarre

Director

Corbin J. Robertson, III

Director

Stephen P. Smith

Director

Leo A. Vecellio, Jr.

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 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 is also Chief Executive Officer and a member of the Board of Managers of Pocahontas Royalties LLC. He also serves as a Principal with Quintana Capital Group, Chairman of the Board of the Cullen Trust for Higher Education and 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 was inducted into the Texas Business Hall of Fame. Mr. Robertson 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 and Treasurer of GP Natural Resource Partners LLC since August 2017 and previously served as Chief Accounting Officer of GP Natural Resource Partners 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 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 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 and the West Virginia University 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.

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 Associations. He also serves on the board of the Cabell-Huntington Hospital.

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. 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.

Alexander D. Greene joined the Board of Directors of GP Natural Resource Partners LLC in March 2019. Mr. Greene brings extensive corporate finance and private equity experience to his role on the Board, with 40 years working with and investing in businesses where operational improvement and strategic guidance were primary drivers of value creation and as a financial advisor to large and mid-cap companies, boards of directors and other constituencies in complex leveraged finance, merger and acquisition and recapitalization transactions. Mr. Greene is a director of Element Fleet Management Corp. and is Chairman of the Board of USA Truck, Inc. From 2005 to 2014 he was a Managing Partner and head of U.S. Private Equity at Brookfield Asset Management, a global asset management company. Prior to Brookfield, Mr. Greene was a Managing Director and co-head of Carlyle Strategic Partners, a private equity fund, and a Managing Director and investment banker at Wasserstein Perella & Co. and Whitman Heffernan Rhein & Co. Mr. Greene is a volunteer firefighter and president of the Armonk Independent Fire Company and serves on the Budget and Finance Advisory Committee for the Town of North Castle, New York. Mr. Greene has been designated to serve as a director of GP Natural Resource Partners LLC by Blackstone Tactical Opportunities, pursuant to its right to designate a director to the Board of Directors of GP Natural Resource Partners LLC.

S. Reed Morian joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive business experience having served as Chairman and Chief Executive Officer of several companies since the early 1980s and serving on the board of other companies. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian also serves on the Board of Managers of Pocahontas Royalties, LLC. Mr. Morian worked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief Executive Officer from 1981 to 2006. He has also served as Chairman, Chief Executive Officer and President of DX Holding Company since 1989. He formerly served on the Board of Directors for the Federal Reserve Bank of Dallas-Houston Branch from April 2003 until December 2008 and as a Director of Prosperity Bancshares, Inc. from March 2005 until April 2009. He is currently serving on the Board of Directors of Gulf Capital Bank in Houston.

Paul B. Murphy, Jr. joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Murphy is the Chairman and Chief Executive Officer and a Director of Cadence Bancorporation and Chairman of Cadence Bank, N.A. He has served at Cadence and its predecessors since December 2009. Cadence is a $18 billion bank holding company headquartered in Houston and it is traded 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, Houston Hispanic Chamber of Commerce, and the City of Houston Complete Advisory Board.

Richard A. Navarre joined the Board of Directors of GP Natural Resource Partners LLC in October 2013. Mr. Navarre brings extensive 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 several 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 Arch Resources, where he serves as Chairman of the Personnel and Compensation Committee and member of the Environmental, Social, Governance and Nominating and Governance Committee. He is a member of the Hall of Fame of the College of Business and a member of the Board of Advisors of 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 has experience with investments in a variety of energy businesses, having served both in management of private equity firms and having served on several boards of directors. Mr. Robertson has served as a Co-Managing Partner of LKCM Headwater Investments GP, LLC, LKCM Headwater Investments I, L.P., LKCM Headwater Investments II, LP, LKCM Headwater Investments II Sidecar, LP, LKCM Headwater Investments III, private equity funds that began June 2011. He has served as the Chief Executive Officer of the general partner of Western Pocahontas Properties Limited Partnership since May 2008, and has served on the Board of Directors of Quintana Minerals Corporation since 2007 and Western Pocahontas since October 2012. Mr. Robertson also has served on the Board of Managers of Premium Resources, LLC since 2016. Mr. Robertson also co-founded Quintana Energy Partners, an energy-focused private equity firm in 2006, and served as a Managing Director thereof from 2006 until December 2010. Mr. Robertson has served on the Board of Directors for Quintana Minerals Corporation since October 2007, and previously served as Vice President-Acquisitions for GP Natural Resource Partners LLC from 2003 until 2005. Mr. Robertson also serves on the Board of Directors of Quality Magnetite, Quinwood Coal and LL&B Minerals, each of which is in the energy business. Mr. Robertson is the son of Corbin J. Robertson, Jr.

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.

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.

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 2021, 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.

As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. Our named executive officers are based in Houston, Texas and employed by Quintana Minerals Corporation (“Quintana”). Quintana is controlled by our Chairman and Chief Executive Officer and is an affiliate of NRP. While our named executive officers are employed by an affiliate 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.

Each named executive officer received a discretionary short-term cash incentive award approved in February 2022 by the CNG Committee. With respect to 2021, the CNG Committee, using recommendations from its independent compensation consultant, Longnecker & Associates, determined that cash bonuses would be paid based on a percentage of base salary. In addition, the CNG Committee determined that it would consider certain criteria to determine bonus amounts, but that the criteria utilized at the time of determination, as well as the relative weight of those criteria, would be generally discretionary and subject to change based on developments at the Partnership.

Awards made to our named executive officers under the 2017 Plan have been made in phantom units that settle in common units on a one-for-one basis with tandem distribution equivalent rights (“DERs”). The phantom unit awards made in 2020 and 2021 time-vest ratably over the three-year period following the grant date and accrue DERs to be paid in cash upon each settlement. Phantom units awarded in 2019 time-vest on the third anniversary of the grant date and accrue DERs to be paid in cash upon settlement. The table below shows the total number of outstanding phantom unit awards under the 2017 Plan held by each named executive officer at December 31, 2021:

For more information regarding the Board 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 2021 consisted of a $75,000 cash retainer and an award of phantom units under the 2017 Plan. The phantom units awarded to Board members in 2021 vest after one year; however, the Board 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. In addition, members of Board committees received $5,000 for each committee served on, and the chairman of the audit, compensation, nominating and governance and conflicts committees received an additional $20,000, $15,000 and $10,000, respectively, for acting as chairman.


Name of Beneficial Owner	Common Units	Percentage of Common Units (1)
Corbin J. Robertson, Jr. (2)	2,478,742	19.8	%

Western Pocahontas Corporation (3)	1,739,007	13.9	%
Western Pocahontas Properties Limited Partnership (4)	1,727,986	13.8	%
JPMorgan Chase & Co. (5)	1,028,351	8.2	%
The Goldman Sachs Group, Inc. (6)	1,112,356	8.9	%
Craig W. Nunez	37,755	*
Christopher J. Zolas	22,259	*








Galdino J. Claro	15,122	*
Alexander D. Greene	—	—
S. Reed Morian (7)	631,521	5.0	%
Paul B. Murphy, Jr.	14,815	*
Richard A. Navarre (8)	12,008	*
Corbin J. Robertson III (9)	249,664	2.0	%
Stephen P. Smith (10)	355	*
Leo A. Vecellio, Jr.	17,362	*
Directors and Officers as a Group (11)	3,513,459	28.1	%

(2)Mr. Robertson, Jr. may be deemed to beneficially own 573,208 common units owned in his individual capacity, 1,739,007 common units in his capacity as controlling shareholder of Western Pocahontas Corporation, 156,000 common units in his capacity as the sole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource Partners, which is the general partner of NRP (GP) LP, 5,293 common units in his capacity as controlling shareholder of GNP Management Corporation and 5,234 common units held by his spouse, Barbara M. Robertson. Mr. Robertson, Jr.’s address is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002.

(9)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, 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 is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002, the address for BHJ Investments is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002 and the address for 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.

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.

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.

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.

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.

Effective on March 2, 2017 in connection with the closing of the issuance of the Preferred Units, we entered into the Board Observation and Representation Rights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant to the Board Rights Agreement, Blackstone appoints one member to serve on the Board of Directors of GP Natural Resource Partners LLC and also appoints one observer to attend meetings of the Board. Blackstone's rights to appoint a member of the Board and an observer will terminate at such time as Blackstone, together with their affiliates, no longer own at least 20% of the total number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). Following the time that Blackstone (and their affiliates) no longer own the Minimum Preferred Unit Threshold and until such time as GoldenTree (together with their affiliates) no longer own the Minimum Preferred Unit Threshold, GoldenTree shall have the one-time option to appoint either one person to serve as a member of the Board or one person to serve as a Board observer. To the extent GoldenTree elects to appoint a Board member and later remove such Board member, GoldenTree may then elect to appoint a Board observer. For more information on the Preferred Units, including the rights of the holders thereof, see "Item 8. Financial Statements and Supplementary Data—Note 4. Class A Convertible Preferred Units and Warrants" elsewhere in this Annual Report on Form 10-K.

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.

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.

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.

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 appendices to this 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 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.

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.

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.


Delaware						35-2164875
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


Large Accelerated Filer	☐	Accelerated Filer	☒
Non-accelerated Filer	☐	Smaller Reporting Company	☒
		Emerging Growth Company	☐


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	20
Item 1B.	Unresolved Staff Comments	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35

PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	[RESERVED]	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 8.	Financial Statements and Supplementary Data	52
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	87
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	89

PART III
Item 10.	Directors and Executive Officers of the Managing General Partner and Corporate Governance	90
Item 11.	Executive Compensation	96
Item 12.	Security Ownership of Certain Beneficial Owners and Management	99
Item 13.	Certain Relationships and Related Transactions, and Director Independence	101
Item 14.	Principal Accountant Fees and Services	108

PART IV
Item 15.	Exhibits, Financial Statement Schedules	111
Signatures		115


For the Year Ended December 31, 2019
	Type of Coal
(Tons in thousands)	Thermal	Metallurgical	Total
Appalachia Basin
Northern	2,781	679	3,460
Central	3,117	10,260	13,377
Southern	470	1,200	1,670
Total Appalachia Basin	6,368	12,139	18,507
Illinois Basin	2,201	—	2,201
Northern Powder River Basin	3,036	—	3,036
Total	11,605	12,139	23,744


	Payments Due by Period
Debt Obligations (In thousands)	Total		2022		2023		2024		2025		2026		Thereafter
NRP:
Debt principal payments (1)	$	300,000	$	—	$	—	$	—	$	300,000	$	—	$	—
Debt interest payments (1)	95,813		27,375		27,375		27,375		13,688		—		—
Opco:
Debt principal payments (including current maturities) (2)	138,484		39,396		39,396		31,028		14,332		14,332		—
Debt interest payments (3)	16,925		7,131		4,895		2,724		1,450		725		—

Total	$	551,222	$	73,902	$	71,666	$	61,127	$	329,470	$	15,057	$	—


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


NATURAL RESOURCE PARTNERS LP
						(Exact name of registrant as specified in its charter)


(In thousands)	Amount		% of Total
Mineral Rights	$	194,493	90%
Soda Ash	21,871		10%

Total	$	216,364	100%


For the Year Ended December 31, 2021
	Type of Coal
(Tons in thousands)	Thermal	Metallurgical	Total
Appalachia Basin
Northern	718	617	1,335
Central	1,140	11,139	12,279
Southern	119	1,452	1,571
Total Appalachia Basin	1,977	13,208	15,185
Illinois Basin	9,388	—	9,388
Northern Powder River Basin	3,151	—	3,151
Gulf Coast	55	—	55
Total	14,571	13,208	27,779


For the Year Ended December 31, 2020
	Type of Coal
(Tons in thousands)	Thermal	Metallurgical	Total
Appalachia Basin
Northern	267	380	647
Central	1,157	8,954	10,111
Southern	143	746	889
Total Appalachia Basin	1,567	10,080	11,647
Illinois Basin	3,381	—	3,381
Northern Powder River Basin	1,738	—	1,738
Total	6,686	10,080	16,766


	For the Year Ended December 31,
Operating Segment (In thousands)	2021		2020		Increase		Percentage Change
Mineral Rights	$	194,493	$	129,592	$	64,901	50	%
Soda Ash	21,871		10,728		11,143		104	%
Total	$	216,364	$	140,320	$	76,044	54	%


	For the Year Ended December 31,				Increase (Decrease)		Percentage Change
(In thousands)	2021		2020
Operating expenses
Operating and maintenance expenses	$	27,049	$	24,795	$	2,254	9	%
Depreciation, depletion and amortization	19,075		9,198		9,877		107	%
General and administrative expenses	17,360		14,293		3,067		21	%
Asset impairments	5,102		135,885		(130,783)		(96)	%
Total operating expenses	$	68,586	$	184,171	$	(115,585)	(63)	%


			Page
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm (PCAOB ID 42)			53
Report of Deloitte & Touche, LLP, Independent Registered Public Accounting Firm (PCAOB ID 34)			55
Consolidated Balance Sheets as of December 31, 2021 and 2020			57
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019			58
Consolidated Statements of Partners’ Capital for the years ended December 31, 2021, 2020 and 2019			59
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019			60
Notes to Consolidated Financial Statements			62


Lease Term (1)	Weighted Average Remaining Years	Annual Minimum Payments
0 - 5 years	2.6	$	18,341
5 - 10 years	4.1	6,823
10+ years	13.5	28,069
Total	8.6	$	53,233


(In thousands, except unit data)	Units Outstanding	Financial Position





Balance at December 31, 2018 and 2019	250,000	$	164,587
Distribution paid-in-kind	3,750	3,750
Balance at December 31, 2020	253,750	$	168,337
Distributions paid-in-kind	15,571	15,571
Balance at December 31, 2021	269,321	$	183,908


(In thousands, except warrant data)	Warrants Outstanding	Financial Position
Balance at December 31, 2018, 2019 and 2020	4,000,000	$	66,816
Warrant settlement	(997,500)	(18,852)
Balance at December 31, 2021	3,002,500	$	47,964


		Cash Distributions								Paid-in-kind Distributions
		Common Units				Preferred Units
Date Paid	Period Covered by Distribution	Distribution per Unit		Total Distribution (1) (In thousands)		Distribution per Unit		Total Distribution (In thousands)		Total Distribution (In units)
2021
February 2021	October 1 - December 31, 2020	$	0.45	$	5,630	$	15.00	$	3,806	3,806
May 2021	January 1 - March 31, 2021	0.45		5,672		15.00		3,864		3,864
August 2021	April 1 - June 30, 2021	0.45		5,671		15.00		3,921		3,921
November 2021	July 1 - September 30, 2021	0.45		5,672		15.00		3,980		3,980

2020
February 2020	October 1 - December 31, 2019	$	0.45	$	5,630	$	30.00	$	7,500	—
May 2020	January 1 - March 31, 2020	—		—		15.00		3,750		3,750
June 2020 (2)	January 1 - March 31, 2020	—		—		15.45		3,863		—
August 2020	April 1 - June 30, 2020	0.45		5,630		30.00		7,500		—
November 2020	July 1 - September 30, 2020	0.45		5,630		15.00		3,750		3,750

2019
February 2019	October 1 - December 31, 2018	$	0.45	$	5,625	$	30.00	$	7,500	—
May 2019	January 1 - March 31, 2019	0.45		5,630		30.00		7,500		—
May 2019 (3)	Special Distribution	0.85		10,635		—		—		—
August 2019	April 1 - June 30, 2019	0.45		5,630		30.00		7,500		—
November 2019	July 1 - September 30, 2019	0.45		5,630		30.00		7,500		—


(In thousands)	Estimated Amortization Expense
2022	$	1,127
2023	1,041
2024	1,238
2025	1,202
2026	1,202


	NRP LP		Opco
(In thousands)	Senior Notes		Senior Notes		Credit Facility		Total
2022	$	—	$	39,396	$	—	$	39,396
2023	—		39,396		—		39,396
2024	—		31,028		—		31,028
2025	300,000		14,332		—		314,332
2026	—		14,332		—		14,332
Thereafter	—		—		—		—
	$	300,000	$	138,484	$	—	$	438,484


(In thousands)	Common Units	Weighted Average Grant Date Fair value per Common Unit
Outstanding grants at January 1, 2021	355	$	26.20
Granted	219	$	17.31
Fully vested and issued	(129)	$	21.38
Forfeitures	(34)	$	26.00
Outstanding at December 31, 2021	411	$	23.00


Remaining Annual Lease Payments (In thousands)	December 31, 2021
2022	$	483
2023	483
2024	483
2025	483
2026	483
After 2026	10,631
Total lease payments (1)	$	13,046
Less: present value adjustment (2)	(9,562)
Total operating lease liability	$	3,484


Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($) (1)	All Other Compensation ($) (2)	Total ($)
Corbin J. Robertson, Jr.—Chief Executive Officer
	2021	—	2,037,340	946,909	—	2,984,249
	2020	—	825,188	1,210,467	—	2,035,655



Craig W. Nunez—President and Chief Operating Officer
	2021	515,000	885,800	717,032	17,400	2,135,232
	2020	515,000	358,778	657,866	17,100	1,548,744


Christopher J. Zolas—Chief Financial Officer
	2021	365,000	502,240	412,549	17,400	1,297,189
	2020	365,000	203,423	276,989	17,100	862,512


Named Executive Officer	Unvested 2017 Plan Phantom Units	Market Value of Unvested 2017 Plan Phantom Units (1)
Corbin J. Robertson, Jr.	133,119 (2)	$	4,448,837
Craig W. Nunez	82,671 (3)	2,762,865
Christopher J. Zolas	46,447 (4)	1,552,259


Name of Director	Fees Earned or Paid in Cash		2017 Plan Common Unit Awards (1)		Total Compensation
S. Reed Morian	$	75,000	$	105,193	$	180,193
Richard A. Navarre (2)	100,000		105,193		205,193
Corbin J. Robertson, III	75,000		105,193		180,193
Stephen P. Smith (3)	105,000		105,193		210,193
Leo A. Vecellio, Jr.	100,000		105,193		205,193
Paul B. Murphy, Jr.	75,000		105,193		180,193
Galdino J. Claro	85,000		105,193		190,193
Alexander D. Greene (4)	—		—		—


Name of Beneficial Owner	Preferred Units	Percentage of Preferred Units
Blackstone Inc. (1)	142,500	57	%
GoldenTree Asset Management, LP (2)	107,500	43	%


	2021		2020
Audit Fees (1)	$	757,450	$	785,750

Tax Fees (2)	412,500		505,915


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).


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).


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									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).
10.9									Board Representation and Observation Rights Agreement dated as of March 2, 2017, by and among Natural Resource Partners L.P., Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, BTO Carbon Holdings L.P. and the GoldenTree Purchasers named therein (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March 6, 2017)
10.10									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).
10.11									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).
10.12									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).
10.13+									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).
10.14+									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).
10.15+									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).
10.16+									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).
10.17+									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).
10.18+									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).
21.1*									List of Subsidiaries of Natural Resource Partners L.P.
23.1*									Consent of Ernst & Young LLP.
23.2*									Consent of Deloitte & Touche LLP.
31.1*									Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
31.2*									Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1**									Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2**									Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
99.1*									Financial Statements of Sisecam Wyoming LLC as of December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019.


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


	NATURAL RESOURCE PARTNERS L.P.
	By:	NRP (GP) LP, its general partner
	By:	GP NATURAL RESOURCE
		PARTNERS LLC, its general partner

Date: March 15, 2022
	By:	/s/ CORBIN J. ROBERTSON, JR.
		Corbin J. Robertson, Jr.
		Chairman of the Board, Director and
		Chief Executive Officer
		(Principal Executive Officer)


Date: March 15, 2022
	By:	/s/ CHRISTOPHER J. ZOLAS
		Christopher J. Zolas
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer)


Date: March 15, 2022
			/s/ GALDINO J. CLARO
			Galdino J. Claro
			Director


Date: March 15, 2022
			/s/ ALEXANDER D. GREENE
			Alexander D. Greene
			Director