# Natural Resource Partners LP: Form 10-K for the period ended Dec 31, 2022

- Company: [Natural Resource Partners LP](/companies/nrp.md) (CIK 1171486)
- Form: 10-K
- Filed: 2023-03-03
- Accepted by EDGAR: Mar 2, 2023, 20:51 ET
- Period: 2022-12-31
- Accession: 0001437749-23-005274
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1171486/000143774923005274/nrp20221231_10k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1171486/000143774923005274/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2022-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2022-01-01 to 2022-12-31 | $307.0m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 12 months, 2022-01-01 to 2022-12-31 | $305.2m | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2022-01-01 to 2022-12-31 | $26.3m | us-gaap:InterestExpense |
| Net income | 12 months, 2022-01-01 to 2022-12-31 | $268.5m | us-gaap:ProfitLoss |
| Operating cash flow | 12 months, 2022-01-01 to 2022-12-31 | $266.8m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2022-01-01 to 2022-12-31 | $118.0k | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2022-12-31 | $39.1m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2022-12-31 | $83.6m | us-gaap:AssetsCurrent |
| Total assets | at 2022-12-31 | $877.1m | us-gaap:Assets |
| Current liabilities | at 2022-12-31 | $60.2m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2022-12-31 | $235.1m | us-gaap:Liabilities |
| Long-term debt | at 2022-12-31 | $129.2m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2022-12-31 | $39.1m | us-gaap:LongTermDebtCurrent |

## Risk factors

As filed, 71,940 characters.

### Risks Related to Our Business

***Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In addition, our debt agreements and our partnership agreement place restrictions on our ability to pay, and in some cases raise, the quarterly distribution under certain circumstances.***

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

Our partnership agreement requires our consolidated leverage ratio to be less than 3.25x in order to make quarterly distributions on the common units in an amount in excess of $0.45 per unit.

For more information on restrictions on our ability to make distributions on our common units, see "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and "Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net."

***Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.***

As of December 31, 2022, we and our subsidiaries had approximately $169.1 million of total indebtedness. The terms and conditions governing the indenture for Opco’s revolving credit facility and senior notes:

- require us to meet certain leverage and interest coverage ratios;
- require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industries in which we operate;
- increase our vulnerability to economic downturns and adverse developments in our business;
- limit our ability to access the bank and capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
- place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
- place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness;
- make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may default on our debt obligations; and
- limit management’s discretion in operating our business.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations, including payment of distributions on the preferred units. If we do not have sufficient funds, we may be required to refinance all or part of our existing debt, borrow more money, or sell assets or raise equity at unattractive prices, including higher interest rates. We are required to make substantial principal repayments each year in connection with Opco’s senior notes, with approximately $40 million due thereunder during 2023. To the extent we borrow to make some of these payments, we may not be able to refinance these amounts on terms acceptable to us, if at all. We may not be able to refinance our debt, sell assets, borrow more money or access the bank and capital markets on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive covenants in our debt agreements will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.

***The ongoing COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and ability to make cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.***

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

As economic activity began to recover throughout 2021 and 2022, so did supply and demand for coal and soda ash. While the outbreak appeared to be trending downward, particularly as vaccination rates increased, new variants of COVID-19 emerged, including the highly transmissible Delta and Omicron variants, spreading throughout the United States and globally and causing significant uncertainty. The full extent to which the COVID-19 pandemic will impact our results is not fully known and is evolving, and will depend on future developments, which are highly uncertain and cannot be predicted. These include the severity, duration and spread of COVID-19, the success of actions taken by governments and health organizations to combat the disease and treat its effects, including additional remedial legislation, the emergence of any new COVID-19 variants that may arise, the timing, availability, effectiveness and adoption rates of vaccines and treatments and the extent to which, and when, general economic and operating conditions recover. Accordingly, any resulting financial impact cannot be reasonably estimated at this time but such amounts may be material. To the extent our board of directors deems necessary, it may determine to suspend cash distributions in future quarters as a result of the pandemic.

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

Coal prices continue to be volatile and prices could decline substantially from current levels. Production by some of our lessees may not be economic if prices decline further or remain at current levels. The prices our lessees receive for their coal depend upon factors beyond their or our control, including:

- the supply of and demand for domestic and foreign coal;
- domestic and foreign governmental regulations and taxes;
- changes in fuel consumption patterns of electric power generators;
- the price and availability of alternative fuels, especially natural gas;
- global economic conditions, including the strength of the U.S. dollar relative to other currencies;
- global and domestic demand for steel;
- tariff rates on imports and trade disputes, particularly involving the United States and China;
- the availability of, proximity to and capacity of transportation networks and facilities;
- global or national health concerns, including the outbreak of pandemic or contagious disease, such as the ongoing COVID-19 pandemic;
- weather conditions; and
- the effect of worldwide energy conservation measures.

Natural gas is the primary fuel that competes with thermal coal for power generation, and renewable energy sources continue to gain market share in power generation. The abundance and ready availability of cheap natural gas, together with increased governmental regulations on the power generation industry has caused a number of utilities to switch from thermal coal to natural gas and/or close coal-powered generation plants. This switching has resulted in a decline in thermal coal prices, and to the extent that natural gas prices remain low, thermal coal prices will also remain low. Reduced international demand for export thermal coal and increased competition from global producers has also put downward pressure on thermal coal prices.

Our lessees produce a significant amount of metallurgical coal that is used for steel production domestically and internationally. Since the amount of steel that is produced is tied to global economic conditions, declines in those conditions could result in the decline of steel, coke and metallurgical coal production. Since metallurgical coal is priced higher than thermal coal, some mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If these mines are unable to sell metallurgical coal, they may not be economically viable and may be temporarily idled or closed. Any potential future lessee bankruptcy filings could create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our business and results of operations.

To the extent our lessees are unable to economically produce coal over the long term, the carrying value of our coal mineral rights could be adversely affected. A long-term asset generally is deemed impaired when the future expected cash flow from its use and disposition is less than its book value. For the year ended December 31, 2022, we recorded impairment charges of approximately $4.5 million related to properties that we believe our current or future lessees are unable to operate profitably. Future impairment analyses could result in additional downward adjustments to the carrying value of our assets.

***Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Sisecam Wyoming’s ability to continue to make distributions to its members and on our results of operations.***

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

***We derive a large percentage of our revenues and other income from a small number of coal lessees.***

Challenges in the coal mining industry have led to significant consolidation activity. We own significant interests in several of Alpha's mining operations, which accounted for approximately 26% of our total revenues in 2022. We also own significant interests in all of Foresight’s mining operations, which accounted for approximately 17% of our total revenues in 2022. Certain other lessees have made acquisitions over the past few years resulting in their having an increased interest in our coal. Any interruption in these lessees’ ability to make royalty payments to us could have a disproportionate material adverse effect on our business and results of operations.

***Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect on our business and results of operations.***

While current coal prices have recovered substantially, the recent coal price environment, together with high operating costs and limited access to capital, has caused a number of coal producers to file for protection under The U.S. Bankruptcy Code and/or idle or close mines that they cannot operate profitably. To the extent our leases are accepted or assigned in a bankruptcy process, pre-petition amounts are required to be cured in full, but we may ultimately make concessions in the financial terms of those leases in order for the reorganized company or new lessor to operate profitably going forward. To the extent our leases are rejected, operations on those leases will cease, and we will be unlikely to recover the full amount of our rejection damages claims. More of our lessees may file for bankruptcy in the future, which will create additional uncertainty as to the future of operations on our properties and could have a material adverse effect on our business and results of operations.

***Mining operations are subject to operating risks that could result in lower revenues to us.***

Our revenues are largely dependent on the level of production of minerals from our properties, and any interruptions to or increases in costs of the production from our properties may reduce our revenues. The level of production and costs thereof are subject to operating conditions or events beyond our or our lessees’ control including:

- difficulties or delays in acquiring necessary permits or mining or surface rights;
- reclamation costs and bonding costs;
- changes or variations in geologic conditions, such as the thickness of the mineral deposits and the amount of rock embedded in or overlying the mineral deposit;
- mining and processing equipment failures and unexpected maintenance problems;
- the availability of equipment or parts and increased costs related thereto;
- the availability of transportation networks and facilities and interruptions due to transportation delays;
- adverse weather and natural disasters, such as heavy rains and flooding;
- labor-related interruptions and trained personnel shortages; and
- mine safety incidents or accidents, including hazardous conditions, roof falls, fires and explosions.

While our lessees maintain insurance coverage, there is no assurance that insurance will be available or cover the costs of these risks. Many of our lessees are experiencing rising costs related to regulatory compliance, insurance coverage, permitting and reclamation bonding, transportation, and labor. Increased costs result in decreased profitability for our lessees and reduce the competitiveness of coal as a fuel source. In addition, we and our lessees may also incur costs and liabilities resulting from third-party claims for damages to property or injury to persons arising from their operations. The occurrence of any of these events or conditions could have a material adverse effect on our business and results of operations.

***The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changes in fuel consumption patterns by electric power generators and a corresponding decrease in coal production by our lessees and reduced coal-related revenues.***

Enactment of laws and passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, have resulted in and could continue to result in electricity generators switching from coal to other fuel sources and in coal-fueled power plant closures. Further, regulations regarding new coal-fueled power plants could adversely impact the global demand for coal. The potential financial impact on us of existing and future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants and environmental and other governmental regulations. We expect that substantially all newly constructed power plants in the United States will be fired by natural gas because of lower construction and compliance costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of rules and regulations promulgated under the federal Clean Air Act have resulted in more electric power generators shifting from coal to natural-gas-fired power plants, or to other alternative energy sources such as solar and wind. These changes have resulted in reduced coal consumption and the production of coal from our properties and are expected to continue to have an adverse effect on our coal-related revenues.

In addition to EPA’s greenhouse gas initiatives, there are several other federal rulemakings that are focused on emissions from coal-fired electric generating facilities, including the Cross-State Air Pollution Rule (CSAPR) as revised in 2021, regulating emissions of nitrogen oxide and sulfur dioxide, and the Mercury and Air Toxics Rule (MATS), regulating emissions of hazardous air pollutants. Installation of additional emissions control technologies and other measures required under these and other EPA regulations have made it more costly to operate many coal-fired power plants and have resulted in and are expected to continue to result in plant closures. Further reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed rules and regulations would have a material adverse effect on our coal-related revenues. For more information on regulation of greenhouse gas and other air pollutant emissions, see "Items 1. and 2. Business and Properties—Regulation and Environmental Matters.”

***Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending and investment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels.***

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

***Increased attention to climate change, environmental, social and governance (ESG) matters and conservation measures may adversely impact our business.***

Increasing attention to climate change, societal expectations on companies to address climate change, and investor and societal expectations regarding ESG matters and disclosures, may result in increased costs, reduced profits, increased investigations and litigation, and negative impacts on our access to capital.

Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, and many of these ratings processes are inconsistent with each other. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Furthermore, if our competitors’ ESG performance is perceived to be greater than ours, potential or current investors may elect to invest in our competitors instead.

***In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state and local laws and regulations that may limit production from our properties and our profitability.***

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

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

In addition to governmental regulation, private citizens’ groups have continued to be active in bringing lawsuits against coal mine operators and land owners that allege violations of water quality standards resulting from ongoing discharges of pollutants from reclaimed mining operations, including selenium and conductivity. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations and could result in substantial compliance costs or fines.

***If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.***

We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

- the payment of minimum royalties;
- marketing of the minerals mined;
- mine plans, including the amount to be mined and the method and timing of mining activities;
- processing and blending minerals;
- expansion plans and capital expenditures;
- credit risk of their customers;
- permitting;
- insurance and surety bonding;
- acquisition of surface rights and other mineral estates;
- employee wages;
- transportation arrangements;
- compliance with applicable laws, including environmental laws; and
- mine closure and reclamation.

A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell minerals at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees.

***We have limited approval rights with respect to the management of our Sisecam Wyoming soda ash joint venture, including with respect to cash distributions and capital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture and through our ownership of certain coal transportation assets.***

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

In addition, we are ultimately responsible for operating the transportation infrastructure at Foresight’s Williamson mine, and have assumed the capital and operating risks associated with that business. As a result of these investments, we could experience increased costs as well as increased liability exposure associated with operating these facilities.

***Sisecam Wyoming’s deca stockpiles will substantially deplete by 2024 and its production rates will decline approximately 200,000 short tons per year if Sisecam Wyoming does not make further investments or otherwise execute on one or more initiatives to prevent such decline.***

In 2024, Sisecam Wyoming’s deca stockpiles will be substantially depleted and Sisecam Wyoming's production rates will decline approximately 200,000 short tons (approximately 7% of Sisecam Wyoming production), which would impact Sisecam Wyoming's profitability. While Sisecam Wyoming is currently evaluating whether and when to pursue one or more initiatives that could offset this decline as well as provide additional soda ash production above current rates, there is no guarantee that any such initiatives or investments will be executed successfully, in a timely manner, or if at all to enable Sisecam Wyoming to maintain its current rates of production.

***Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal, soda ash and other minerals from our properties.***

Transportation costs represent a significant portion of the total delivered cost for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make minerals produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from producers in other parts of the country.

Our lessees depend upon railroads, barges, trucks and beltlines to deliver minerals to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and/or other events could temporarily impair the ability of our lessees to supply coal to their customers and/or increase their costs. Many of our lessees are currently experiencing transportation-related issues due in particular to decreased availability and reliability of rail services and port congestion. Our lessees’ transportation providers may face difficulties in the future that would impair the ability of our lessees to supply minerals to their customers, resulting in decreased royalty revenues to us.

In addition, Sisecam Wyoming transports its soda ash by rail or truck and ocean vessel. As a result, its business and financial results are sensitive to increases in rail freight, trucking and ocean vessel rates. Increases in transportation costs, including increases resulting from emission control requirements, port taxes and fluctuations in the price of fuel, could make soda ash a less competitive product for glass manufacturers when compared to glass substitutes or recycled glass, or could make Sisecam Wyoming’s soda ash less competitive than soda ash produced by competitors that have other means of transportation or are located closer to their customers. Sisecam Wyoming may be unable to pass on its freight and other transportation costs in full because market prices for soda ash are generally determined by supply and demand forces. In addition, rail operations are subject to various risks that may result in a delay or lack of service at Sisecam Wyoming’s facility, and alternative methods of transportation are impracticable or cost prohibitive. For the year ended December 31, 2022, Sisecam Wyoming shipped over 90% of its soda ash from the Green River facility on a single rail line owned and controlled by Union Pacific. Any substantial interruption in or increased costs related to the transportation of Sisecam Wyoming’s soda ash or the failure to renew the rail contract on favorable terms could have a material adverse effect on our financial condition and results of operations.

***Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.***

Mineral supply contracts generally do not require operators to satisfy their obligations to their customers with resources mined from specific locations. Several factors may influence a lessee’s decision to supply its customers with minerals mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. In addition, lessees move on and off of our properties over the course of any given year in accordance with their mine plans. If a lessee satisfies its obligations to its customers with minerals from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues.

***A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.***

We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with our lessees.

### Risks Related to Our Structure

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

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

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

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

- generally, if a person (other than the holders of preferred units) acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and
- our partnership agreement contains limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of management.

As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

***The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future, which could result in substantial dilution of our common unitholders’ ownership interests.***

The preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. We are required to pay quarterly distributions on the preferred units (plus any PIK units issued in lieu of preferred units) in an amount equal to 12.0% per year prior to paying any distributions on our common units. The preferred units also rank senior to the common units in right of liquidation and will be entitled to receive a liquidation preference in any such case.

The preferred units may also be converted into common units under certain circumstances. The number of common units issued in any conversion will be based on the then-current trading price of the common units at the time of conversion. Accordingly, the lower the trading price of our common units at the time of conversion, the greater the number of common units that will be issued upon conversion of the preferred units, which would result in greater dilution to our existing common unitholders. Dilution has the following effects on our common unitholders:

- an existing unitholder’s proportionate ownership interest in NRP will decrease;
- the amount of cash available for distribution on each unit may decrease;
- the relative voting strength of each previously outstanding unit may be diminished; and
- the market price of the common units may decline.

In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the preferred will have the right to remove our general partner.

***We may issue additional common units or preferred units without common unitholder approval, which would dilute a unitholder’s existing ownership interests.***

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

- an existing unitholder’s proportionate ownership interest in NRP will decrease;
- the amount of cash available for distribution on each unit may decrease; and
- the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline.

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

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

***Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.***

Prior to making any distribution on the common units, we reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner.

***Conflicts of interest could arise among our general partner and us or the unitholders.***

These conflicts may include the following:

- We do not have any employees and we rely solely on employees of affiliates of the general partner;
- under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;
- the amount of cash expenditures, borrowings and reserves in any quarter may affect cash available to pay quarterly distributions to unitholders;
- the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability;
- under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arm’s-length negotiations; and
- the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights to one of its affiliates or to us.

In addition, Blackstone has certain consent rights and board appointment and observation rights. GoldenTree also has more limited consent rights. In the exercise of their applicable consent rights and/or board rights, conflicts of interest could arise between us and our general partner on the one hand, and Blackstone or GoldenTree on the other hand.

***The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.***

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors and officers with its own choices and to control their decisions and actions.

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

***Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.***

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Under Delaware law, however, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

### Tax Risks to Our Unitholders

***Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.***

The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based on our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate and would likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We currently own assets and conduct business in several states, many of which impose a margin or franchise tax. In the future, we may expand our operations. Imposition of a similar tax on us in a jurisdiction in which we operate or in other jurisdictions to which we may expand could substantially reduce the cash available for distribution to our unitholders.

***The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.***

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.

Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our units.

***Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.***

Changes to U.S. federal income tax laws have been proposed in a prior session of Congress that would eliminate certain key U.S. federal income tax preferences relating to coal exploration and development. These changes include, but are not limited to (i) repealing capital gains treatment of coal and lignite royalties, (ii) eliminating current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, and (iii) repealing the percentage depletion allowance with respect to coal properties. If enacted, these changes would limit or eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

***Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities.***

Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.

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

***We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including income and gain from the sale of properties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions made with respect to their units.***

We may engage in transactions to reduce our leverage and manage our liquidity that would result in income and gain to our unitholders without a corresponding cash distribution. For example, we may sell assets and use the proceeds to repay existing debt, in which case, our unitholders could be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as ordinary taxable income. Our unitholders may be allocated income and gain from these transactions, and income tax liabilities arising therefrom may exceed any distributions we make to our unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder's individual tax position, including, for example, the availability of any suspended passive losses that may offset some portion of the allocable income. Our unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to the unitholder’s ultimate disposition of its units. Our unitholders are encouraged to consult their tax advisors with respect to the consequences to them.

***If the IRS contests the U.S. federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.***

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

***If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.***

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under these rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

***Tax gain or loss on the disposition of our common units could be more or less than expected.***

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Distributions in excess of a common unitholder's allocable share of our net taxable income result in a decrease in the tax basis in such unitholder's common units. Accordingly, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income to our common unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

***Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.***

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income. If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

***Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.***

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our units.

***Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our units.***

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. As we do not compute our cumulative net income for such purposes due to the complexity of the calculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

***We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.***

Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.

***We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.***

In determining the items of income, gain, loss and deduction allocable to our unitholders, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from the sale of our common units, have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

***We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.***

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

***A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.***

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

***As a result of investing in our units, our unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.***

In addition to U.S. federal income taxes, our unitholders are likely subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in a number of states in the United States. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal, state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

### General Risks

### Our business is subject to cybersecurity risks.

Our business is increasingly dependent on information technologies and services. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Although we utilize various procedures and controls to mitigate our exposure to such risks, cybersecurity attacks and other cyber events are evolving, unpredictable, and sometimes difficult to detect, and could lead to unauthorized access to sensitive information or render data or systems unusable.

While we presently maintain insurance coverage to protect against cybersecurity risks, we cannot ensure that it will be sufficient to cover any particular losses we may experience as a result of such cyber-attacks. Any cyber incident could have a material adverse effect on our business, financial condition and results of operations.

## Legal proceedings

As filed, 326 characters.

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, management believes these ordinary course matters will not have a material effect on our financial position, liquidity or operations.

## Management's discussion and analysis

As filed, 48,517 characters.

### Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consists of the following subjects:

- Executive Overview
- Results of Operations
- Liquidity and Capital Resources
- Inflation
- Environmental Regulation
- Related Party Transactions
- Summary of Critical Accounting Estimates
- Recent Accounting Standards

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

### Non-GAAP Financial Measures

### Distributable Cash Flow

Distributable cash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings, proceeds from asset sales and disposals, including sales of discontinued operations, and return of long-term contract receivables, less maintenance capital expenditures. DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies. In addition, DCF presented below is not calculated or presented on the same basis as distributable cash flow as defined in our partnership agreement, which is used as a metric to determine whether we are able to increase quarterly distributions to our common unitholders. DCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess our ability to make cash distributions and repay debt.

### Free Cash Flow

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

### Cash Flow Cushion

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

### Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) less equity earnings from unconsolidated investment, net income attributable to non-controlling interest and gain on reserve swap; plus total distributions from unconsolidated investment, interest expense, net, debt modification expense, loss on extinguishment of debt, depreciation, depletion and amortization and asset impairments. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies. In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnership agreement or Consolidated EBITDDA as defined in Opco's debt agreements. See "Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net" included elsewhere in this Annual Report on Form 10-K for a description of Opco’s debt agreements. Adjusted EBITDA is a supplemental performance measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.

### Leverage Ratio

Leverage ratio represents the outstanding principal of NRP's debt at the end of the period divided by the last twelve months' Adjusted EBITDA as defined above. NRP believes that leverage ratio is a useful measure to management and investors to evaluate and monitor the indebtedness of NRP relative to its ability to generate income to service such debt and in understanding trends in NRP’s overall financial condition. Leverage ratio may not be calculated the same for us as for other companies and is not a substitute for, and should not be used in conjunction with, GAAP financial ratios.

### Executive Overview

We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal and other natural resources and own a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), a trona ore mining and soda ash production business. Our common units trade on the New York Stock Exchange under the symbol "NRP." Our business is organized into two operating segments:

**Mineral Rights—**consists of approximately 13 million acres of mineral interests and other subsurface rights across the United States. If combined in a single tract, our ownership would cover roughly 20,000 square miles. Our ownership provides critical inputs for the manufacturing of steel, electricity and basic building materials, as well as opportunities for carbon sequestration and renewable energy. We are working to strategically redefine our business as a key player in the transitional energy economy in the years to come.

**Soda Ash—**consists of our 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining and soda ash production business located in the Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries.

Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest and financing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment.

Our financial results by segment for the year ended December 31, 2022 are as follows:

*(In thousands)*

|  | Operating Segments Mineral Rights | Soda Ash | Corporate and Financing | Total |
| --- | ---: | ---: | ---: | ---: |
| Revenues and other income | $329,167 | $59,795 | $— | $388,962 |
| Net income (loss) | $267,448 | $59,635 | $(58,591) | $268,492 |
| Asset impairments | 4,457 | — | — | 4,457 |
| Net income (loss) excluding asset impairments | $271,905 | $59,635 | $(58,591) | $272,949 |
| Adjusted EBITDA (1) | $294,424 | $44,675 | $(21,852) | $317,247 |
| Cash flow provided by (used in) continuing operations |  |  |  |  |
| Operating activities | $262,807 | $44,672 | $(40,641) | $266,838 |
| Investing activities | $2,806 | $— | $(118) | $2,688 |
| Financing activities | $(614) | $— | $(365,341) | $(365,955) |
| Distributable cash flow (1) | $265,613 | $44,672 | $(40,759) | $269,526 |
| Free cash flow (1) | $264,530 | $44,672 | $(40,759) | $268,443 |
| Cash flow cushion (1) | N/A | N/A | N/A | $145,084 |

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

### Current Results/Market Commentary

### Business Outlook and Quarterly Distributions

We generated $266.8 million of operating cash flow and $268.4 million of free cash flow during the year ended December 31, 2022, and ended the year with $99.1 million of liquidity consisting of $39.1 million of cash and cash equivalents and $60 million of borrowing capacity under our Opco Credit Facility. During the year, we refinanced, upsized, and extended our Opco Credit Facility to $130 million due 2027. Also during the year, we permanently retired all $300 million of our 2025 Senior Notes. As of December 31, 2022 our leverage ratio was 0.5x.

In February 2023, the Board of Directors declared a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2022 as well as a $7.5 million cash distribution on the preferred units with respect to the fourth quarter of 2022. Additionally, NRP has announced it will pay a one-time, special cash distribution of $2.43 in March 2023 to help cover unitholder tax liabilities for 2022. Future distributions on our common and preferred units will be determined on a quarterly basis by the Board of Directors. The Board of Directors considers numerous factors each quarter in determining cash distributions, including profitability, cash flow, debt service obligations, market conditions and outlook, estimated unitholder income tax liability and the level of cash reserves that the Board determines is necessary for future operating and capital needs.

In February 2023, we received a notice from holders of our Class A Preferred Units exercising their right to either convert or redeem, at the election of NRP, an aggregate of 47,499 Class A Preferred Units. We chose to redeem the preferred units for $47.5 million in cash plus any accrued and unpaid distributions, utilizing cash on hand and borrowings under our revolving credit facility. Of the originally issued 250,000 Class A Preferred Units, 202,501 Class A Preferred Units remain outstanding as of the date of this report.

### Mineral Rights Business Segment

Metallurgical coal prices reached historical highs and were the primary driver of strong segment performance. Numerous factors continue to provide support for met pricing. Supply chain disruptions, labor shortages and years of underinvestment in new coal production capacity continue to undermine producers’ ability to bring new production online to meet demand. While met prices have pulled back from the peaks reached last year, we continue to believe met prices will remain well-supported for the foreseeable future.

Thermal coal prices also reached record highs in 2022, but have declined significantly in recent months due to unusually warm weather in Europe and North America as well as lower natural gas prices. While we do not expect to see thermal prices rebound to last year’s levels, many of the factors that provided support to prices over the last year still exist. Boycotts of Russian coal continue to force European buyers to source coal from other regions, including the U.S. Operators will continue to be burdened by labor shortages, pressure from governments, regulators, activists, and capital providers, which will limit ability to increase thermal production to meet demand. China appears to be relaxing its three-year ban on Australian coal imports with the recent approvals for several Chinese companies to buy Australian coal. Additional demand from a Chinese economy emerging from a zero-COVID policy should provide additional support for prices. We expect these factors to keep thermal prices elevated relative to historical levels for the foreseeable future

We continue to explore and identify carbon neutral revenue sources across our large portfolio of land and mineral assets. The types of opportunities include the sequestration of carbon dioxide underground and in standing forests, and the generation of green electricity using geothermal, solar, and wind energy. We own the rights to sequester carbon dioxide ("CO2") on approximately 3.5 million acres of pore space in the southern United States. As announced previously, in the first quarter of 2022 we executed our first subsurface CO2 sequestration lease on 75,000 acres of underground pore space we own in southwest Alabama with the potential to store over 300 million metric tons of CO2. In October of 2022, we announced our second subsurface CO2 transaction with the execution of a lease for approximately 65,000 acres of pore space we control near southeast Texas with estimated storage capacity of at least 500 million metric tons of CO2. In total, we have approximately 140,000 acres of pore space under lease for carbon sequestration with estimated CO2 storage capacity of 800 million metric tons. While the timing and likelihood of additional cash flows being realized from these activities is uncertain, we believe our large ownership footprint throughout the United States provides additional opportunities to create value in this regard with minimal capital investment by us.

### Soda Ash Business Segment

Revenues and other income during the year ended December 31, 2022 were higher by $37.9 million compared to the prior year period primarily as a result of increased international sales prices. Cash provided by operating activities and free cash flow during the year ended December 31, 2022 increased $33.6 million as compared to the prior year period due to Sisecam Wyoming reinstating its regular quarterly cash distributions beginning in the fourth quarter of 2021.

Strong international sales at Sisecam Wyoming for the year ended December 31, 2022, more than offset input cost inflation, supply chain difficulties, and softening demand in the second half of the year due to China's Zero-Covid policy and concerns of slowing economic growth.

### Results of Operations

### Year Ended December 31, 2022 and 2021 Compared

### Revenues and Other Income

The following table includes our revenues and other income by operating segment:

| Operating Segment (In thousands) | For the Year Ended December 31, 2022 | 2021 | Increase | Percentage Change |
| --- | ---: | ---: | ---: | ---: |
| Mineral Rights | $329,167 | $194,493 | $134,674 | 69% |
| Soda Ash | 59,795 | 21,871 | 37,924 | 173% |
| Total | $388,962 | $216,364 | $172,598 | 80% |

31

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

### Mineral Rights

The following table presents coal sales volumes, coal royalty revenue per ton and coal royalty revenues by major coal producing region, the significant categories of other revenues and other income:

*(In thousands, except per ton data)*

| Coal sales volumes (tons) Appalachia | For the Year Ended December 31, 2022 | 2021 | Increase (Decrease) | Percentage Change |
| --- | ---: | ---: | ---: | ---: |
| Northern | 1,696 | 1,335 | 361 | 27% |
| Central | 13,646 | 12,279 | 1,367 | 11% |
| Southern | 1,784 | 1,571 | 213 | 14% |
| Total Appalachia | 17,126 | 15,185 | 1,941 | 13% |
| Illinois Basin | 11,135 | 9,388 | 1,747 | 19% |
| Northern Powder River Basin | 4,288 | 3,151 | 1,137 | 36% |
| Gulf Coast | 385 | 55 | 330 | 600% |
| Total coal sales volumes | 32,934 | 27,779 | 5,155 | 19% |
| Coal royalty revenue per ton |  |  |  |  |
| Appalachia |  |  |  |  |
| Northern | $8.75 | $6.51 | $2.24 | 34% |
| Central | 10.47 | 5.71 | 4.76 | 83% |
| Southern | 13.50 | 9.14 | 4.36 | 48% |
| Illinois Basin | 2.50 | 2.12 | 0.38 | 18% |
| Northern Powder River Basin | 4.07 | 3.54 | 0.53 | 15% |
| Gulf Coast | 0.58 | 0.60 | (0.02) | (3)% |
| Combined average coal royalty revenue per ton | 6.90 | 4.47 | 2.43 | 54% |
| Coal royalty revenues |  |  |  |  |
| Appalachia |  |  |  |  |
| Northern | $14,836 | $8,691 | $6,145 | 71% |
| Central | 142,930 | 70,149 | 72,781 | 104% |
| Southern | 24,076 | 14,355 | 9,721 | 68% |
| Total Appalachia | 181,842 | 93,195 | 88,647 | 95% |
| Illinois Basin | 27,856 | 19,917 | 7,939 | 40% |
| Northern Powder River Basin | 17,437 | 11,151 | 6,286 | 56% |
| Gulf Coast | 223 | 33 | 190 | 576% |
| Unadjusted coal royalty revenues | 227,358 | 124,296 | 103,062 | 83% |
| Coal royalty adjustment for minimum leases | (402) | (20,207) | 19,805 | 98% |
| Total coal royalty revenues | $226,956 | $104,089 | $122,867 | 118% |
| Other revenues |  |  |  |  |
| Production lease minimum revenues | $5,854 | $14,269 | $(8,415) | (59)% |
| Minimum lease straight-line revenues | 18,792 | 20,564 | (1,772) | (9)% |
| Carbon neutral initiative revenues | 8,600 | 13,790 | (5,190) | (38)% |
| Wheelage revenues | 13,961 | 10,065 | 3,896 | 39% |
| Property tax revenues | 5,878 | 6,028 | (150) | (2)% |
| Coal overriding royalty revenues | 3,434 | 4,367 | (933) | (21)% |
| Lease amendment revenues | 3,201 | 4,696 | (1,495) | (32)% |
| Aggregates royalty revenues | 3,299 | 1,889 | 1,410 | 75% |
| Oil and gas royalty revenues | 16,161 | 4,506 | 11,655 | 259% |
| Other revenues | 877 | 933 | (56) | (6)% |
| Total other revenues | $80,057 | $81,107 | $(1,050) | (1)% |
| Royalty and other mineral rights | $307,013 | $185,196 | $121,817 | 66% |
| Transportation and processing services revenues | 21,072 | 9,052 | 12,020 | 133% |
| Gain on asset sales and disposals | 1,082 | 245 | 837 | 342% |
| Total Mineral Rights segment revenues and other income | $329,167 | $194,493 | $134,674 | 69% |

32

#### Coal Royalty Revenues

Approximately 70% of coal royalty revenues and approximately 45% of coal royalty sales volumes were derived from metallurgical coal during the year ended December 31, 2022. Total coal royalty revenues increased $122.9 million from 2021 to 2022. Strong coal prices in 2022 were primarily driven by improved demand combined with a limited ability for operators to increase production due to ongoing labor shortages, global supply chain interruptions, and limited access to capital. The discussion by region is as follows:

- Appalachia: Coal royalty revenues increased $88.6 million primarily due to increased coal sales prices and volumes during the year ended December 31, 2022, as compared to the prior year.
- Illinois Basin: Coal royalty revenues increased $7.9 million primarily due to higher sales volumes and increased sales prices during the year ended December 31, 2022 as compared during the prior year. Revenues recognized from Foresight in 2021 were fixed as a result of the lease amendment the Partnership entered into with Foresight in 2020 pursuant to which Foresight agreed to pay NRP fixed cash payments in 2020 and 2021 to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreements between the Partnership and Foresight. Revenues from Foresight in 2022 represent traditional royalty and minimum payments.
- Northern Powder River Basin: Coal royalty revenues increased $6.3 million primarily due to increased sales volumes as our lessee mined more on our property during 2022 as compared to 2021in accordance with its mine plan.

#### Other Revenues

Other revenues decreased $1.1 million during the year ended December 31, 2022 as compared to the prior year primarily due to the following:

- An $8.4 million decrease in production lease minimum revenues primarily due to the lease amendment with Foresight whereas transportation and processing revenues were based on the recognition of a fixed amount in 2021.
- A $5.2 million decrease in carbon neutral initiative revenues as compared to the prior year. Revenues recognized in 2022 related to carbon neutral transactions that included subsurface CO2 storage and geothermal while revenues recognized in 2021 related to forest CO2 sequestration revenues.

These decreases were partially offset by an $11.7 million increase in oil and gas royalty revenues primarily due to new wells and increased natural gas prices as compared to the prior year.

#### Transportation and Processing Services Revenues

Transportation and processing services revenues increased $12.0 million during the year ended December 31, 2022 as compared to the prior year primarily due to the lease amendment with Foresight whereas transportation and processing revenues were based on the recognition of a fixed amount in 2021. Revenues from Foresight in 2022 represented traditional royalty and minimum payments and were greater than the fixed revenue from 2021.

### Soda Ash

Revenues and other income related to our Soda Ash segment increased $37.9 million compared to the prior year primarily as a result of increased international sales prices.

### Operating and Other Expenses

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

*(In thousands)*

| Operating expenses | For the Year Ended December 31, 2022 | 2021 | Increase (Decrease) | Percentage Change |
| --- | ---: | ---: | ---: | ---: |
| Operating and maintenance expenses | $34,903 | $27,049 | $7,854 | 29% |
| Depreciation, depletion and amortization | 22,519 | 19,075 | 3,444 | 18% |
| General and administrative expenses | 21,852 | 17,360 | 4,492 | 26% |
| Asset impairments | 4,457 | 5,102 | (645) | (13)% |
| Total operating expenses | $83,731 | $68,586 | $15,145 | 22% |
| Other expenses, net |  |  |  |  |
| Interest expense, net | $26,274 | $38,876 | $(12,602) | (32)% |
| Loss on extinguishment of debt | 10,465 | — | 10,465 | 100% |
| Total other expenses, net | $36,739 | $38,876 | $(2,137) | (5)% |

Total operating expenses increased $15.1 million primarily due to the following:

- A $7.9 million increase in operating and maintenance expenses primarily as a result of higher overriding royalty expense from an agreement with WPPLP in 2022 as compared to 2021. This overriding royalty expense is fully offset by coal royalty revenue we receive from this property.
- A $4.5 million increase in general and administrative expenses primarily due to increased incentive compensation expense incurred during 2022 as a result of the Partnership's improved performance as compared to the prior year.
- A $3.4 million increase in depreciation, depletion and amortization expense primarily as a result of higher Illinois Basin coal royalty sales volumes during the year ended December 31, 2022, as compared to the prior year.

Total other expenses, net decreased $2.1 million primarily due to a $12.6 million decrease in interest expense, net as a result of less debt outstanding as compared to the prior year, partially offset by a $10.5 million loss on early extinguishment of debt related to the premiums and fees incurrent and write-off of debt issuance costs associated with the retirement of the 2025 Senior Notes during the year ended December 31, 2022.

### Adjusted EBITDA (Non-GAAP Financial Measure)

The following table reconciles net income (loss) (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment:

| For the Year Ended (In thousands) December 31, 2022 | Operating Segments Mineral Rights | Soda Ash | Corporate and Financing | Total |
| --- | ---: | ---: | ---: | ---: |
| Net income (loss) | $267,448 | $59,635 | $(58,591) | $268,492 |
| Less: equity earnings from unconsolidated investment | — | (59,795) | — | (59,795) |
| Add: total distributions from unconsolidated investment | — | 44,835 | — | 44,835 |
| Add: interest expense, net | — | — | 26,274 | 26,274 |
| Add: loss on extinguishment of debt | — | — | 10,465 | 10,465 |
| Add: depreciation, depletion and amortization | 22,519 | — | — | 22,519 |
| Add: asset impairments | 4,457 | — | — | 4,457 |
| Adjusted EBITDA | $294,424 | $44,675 | $(21,852) | $317,247 |
| December 31, 2021 |  |  |  |  |
| Net income (loss) | $143,412 | $21,702 | $(56,212) | $108,902 |
| Less: equity earnings from unconsolidated investment | — | (21,871) | — | (21,871) |
| Add: total distributions from unconsolidated investment | — | 11,270 | — | 11,270 |
| Add: interest expense, net | 24 | — | 38,852 | 38,876 |
| Add: depreciation, depletion and amortization | 19,075 | — | — | 19,075 |
| Add: asset impairments | 5,102 | — | — | 5,102 |
| Adjusted EBITDA | $167,613 | $11,101 | $(17,360) | $161,354 |

Net income increased $159.6 million primarily due to the increases in revenues and other income, partially offset by increased operating expenses, both as discussed above. Adjusted EBITDA increased $155.9 million primarily due to a $126.8 million increase in Adjusted EBITDA within our Mineral Rights segment as a result of higher revenues and other income during the year ended December 31, 2022 as discussed above and a $33.6 million increase in Adjusted EBITDA within our Soda Ash segment as a result of higher cash distributions received from Sisecam Wyoming during the year ended December 31, 2022 as compared to the prior year due to Sisecam Wyoming reinstating its regular quarterly cash distributions beginning in the fourth quarter of 2021.

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

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

| For the Year Ended (In thousands) December 31, 2022 Cash flow provided by (used in) continuing operations | Operating Segments Mineral Rights | Soda Ash | Corporate and Financing | Total |
| --- | ---: | ---: | ---: | ---: |
| Operating activities | $262,807 | $44,672 | $(40,641) | $266,838 |
| Investing activities | 2,806 | — | (118) | 2,688 |
| Financing activities | (614) | — | (365,341) | (365,955) |
| December 31, 2021 |  |  |  |  |
| Cash flow provided by (used in) continuing operations |  |  |  |  |
| Operating activities | $159,845 | $11,106 | $(49,147) | $121,804 |
| Investing activities | 2,412 | — | — | 2,412 |
| Financing activities | (1,132) | — | (87,354) | (88,486) |

34

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

| For the Year Ended (In thousands) December 31, 2022 | Operating Segments Mineral Rights | Soda Ash | Corporate and Financing | Total |
| --- | ---: | ---: | ---: | ---: |
| Net cash provided by (used in) operating activities of continuing operations | $262,807 | $44,672 | $(40,641) | $266,838 |
| Add: proceeds from asset sales and disposals | 1,083 | — | — | 1,083 |
| Add: return of long-term contract receivable | 1,723 | — | — | 1,723 |
| Less: maintenance capital expenditures | — | — | (118) | (118) |
| Distributable cash flow | $265,613 | $44,672 | $(40,759) | $269,526 |
| Less: proceeds from asset sales and disposals | (1,083) | — | — | (1,083) |
| Free cash flow | $264,530 | $44,672 | $(40,759) | $268,443 |
| Less: mandatory Opco debt repayments |  |  |  | (39,396) |
| Less: preferred unit distributions and redemption of PIK units |  |  |  | (49,579) |
| Less: common unit distributions |  |  |  | (34,384) |
| Cash flow cushion |  |  |  | $145,084 |

| For the Year Ended (In thousands) December 31, 2021 | Operating Segments Mineral Rights | Soda Ash | Corporate and Financing | Total |
| --- | ---: | ---: | ---: | ---: |
| Net cash provided by (used in) operating activities of continuing operations | $159,845 | $11,106 | $(49,147) | $121,804 |
| Add: proceeds from asset sales and disposals | 249 | — | — | 249 |
| Add: return of long-term contract receivable | 2,163 | — | — | 2,163 |
| Distributable cash flow | $162,257 | $11,106 | $(49,147) | $124,216 |
| Less: proceeds from asset sales and disposals | (249) | — | — | (249) |
| Less: acquisition costs | (1,000) | — | — | (1,000) |
| Free cash flow | $161,008 | $11,106 | $(49,147) | $122,967 |
| Less: mandatory Opco debt repayments |  |  |  | (39,396) |
| Less: preferred unit distributions |  |  |  | (15,571) |
| Less: common unit distributions |  |  |  | (22,645) |
| Less: warrant cash settlement |  |  |  | (9,183) |
| Cash flow cushion |  |  |  | $36,172 |

Cash provided by operating activities, DCF and FCF increased $145.0 million, $145.3 million and $145.5 million, respectively, primarily due to the following:

- Mineral Rights Segment: Cash provided by operating activities, DCF and FCF increased $103.0 million, $103.4 million and $103.5 million, respectively primarily due to the segment's increase in revenues and other income as discussed above.
- Soda Ash Segment: Cash provided by operating activities, DCF and FCF increased $33.6 million as a result of higher cash distributions received from Sisecam Wyoming in 2022 as compared to the prior year as discussed above.
- Corporate and Financing Segment: Cash used by operating activities decreased $8.5 million and DCF and FCF increased $8.4 million primarily due to lower cash paid for interest in 2022 as a result of the repayments of our 2025 Senior Notes during the year.

Cash flow cushion increased $108.9 million as a result of the increase in FCF discussed above and $9.2 million of cash used to settle the exercise of certain of our warrants in 2021, partially offset by:

- $34.0 million of increased cash paid with respect to our preferred units. In 2021 we paid half of our preferred unit distributions in kind and in 2022 we paid all of our preferred unit distributions in cash and redeemed the outstanding paid-in-kind units.
- $11.7 million of increased cash used for common unit distributions as a result of increasing our common unit distributions to $0.75/unit beginning in the second quarter of 2022.

For discussion of our Results of Operations comparing 2021 to 2020, refer to our 2021 Annual Report on Form 10-K filed March 15, 2022 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

### Liquidity and Capital Resources

### Current Liquidity

As of December 31, 2022, we had total liquidity of $99.1 million, consisting of $39.1 million of cash and cash equivalents and $60 million in borrowing capacity under our Opco Credit Facility. We have debt service obligations, including approximately $40 million of principal repayments on Opco’s senior notes in 2023. As discussed previously, during 2022 we permanently retired all of our 9.125% Senior Notes due 2025 and had $70 million drawn on our Opco Credit Facility as of December 31, 2022. We believe our liquidity position provides us with the flexibility to continue paying down debt and manage our business. As of December 31, 2022 our leverage ratio was 0.5x. The following table calculates our leverage ratio:

*(In thousands)*

|  | For the Year Ended December 31, 2022 |
| --- | ---: |
| Adjusted EBITDA | $317,247 |
| Debt—at December 31, 2022 | $169,087 |
| Leverage Ratio | 0.5x |

### Cash Flows

### Year Ended December 31, 2022 and 2021 Compared

Cash flows provided by operating activities increased $145.0 million, from $121.8 million in the year ended December 31, 2021 to $266.8 million in the year ended December 31, 2022 primarily related to increased revenues and other income within our Mineral Rights segment, higher cash distributions received from Sisecam Wyoming, and less cash paid for interest as compared to the prior year, all as discussed above.

Cash flows used in financing activities increased $277.5 million, from $88.5 million in the year ended December 31, 2021 to $366.0 million in the year ended December 31, 2022 primarily due to the following:

- $300.0 million of cash used to retire all of our 2025 Senior Notes in 2022;
- $19.6 million of cash used to redeem the preferred units paid-in-kind during the first quarter of 2022;
- $14.4 million of increased cash used for preferred unit distributions as a result of paying all of our preferred unit distributions in cash in 2022 as compared to a portion in kind in 2021;
- $11.9 million of increased cash used for other items, net, which primarily related to the premiums paid related to the repayment of the 2025 Senior Notes in 2022; and
- $11.7 million of increased cash used for distributions to common unitholders and the general partner as a result of increasing our common unit distributions to $0.75/unit beginning in the second quarter of 2022.

These increases in cash flow used were partially offset by $70 million of borrowings on our Opco Credit Facility in 2022 and $9.2 million of cash used in 2021 to settle the exercise of certain of our warrants.

For discussion of our Cash Flows comparing 2021 to 2020, refer to our 2021 Annual Report on Form 10-K filed March 15, 2022 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

### Capital Resources and Obligations

### Debt, Net

We had the following debt outstanding as of December 31, 2022 and 2021:

*(In thousands)*

|  | December 31, 2022 | 2021 |
| --- | ---: | ---: |
| Current portion of long-term debt, net | $39,076 | $39,102 |
| Long-term debt, net | 129,205 | 394,443 |
| Total debt, net | $168,281 | $433,545 |

We have been and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information regarding our debt and the agreements governing our debt, including the covenants contained therein, see "Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net" in this Annual Report on Form 10-K.

### Debt Obligations

The following table reflects our long-term, non-cancelable debt obligations as of December 31, 2022:

| Debt Obligations (In thousands) NRP: | Payments Due by Period Total | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Debt principal payments | $— | $— | $— | $— | $— | $— | $— |
| Debt interest payments | — | — | — | — | — | — | — |
| Opco: |  |  |  |  |  |  |  |
| Debt principal payments (including current maturities) (1) | 169,087 | 39,396 | 31,028 | 14,332 | 14,331 | 70,000 | — |
| Debt interest payments (2) | 9,794 | 4,895 | 2,724 | 1,450 | 725 | — | — |
| Total | $178,881 | $44,291 | $33,752 | $15,782 | $15,056 | $70,000 | $— |

(1) The amounts indicated in the table include principal due on Opco’s senior notes and credit facility.

(2) The amounts indicated in the table include interest due on Opco’s senior notes.

### Inflation

Inflation in the United States has been relatively low in previous years, and despite rising costs beginning in 2021 and continuing into 2022, inflation did not have a material impact on operations for the years ended December 31, 2022, 2021 and 2020.

### Environmental Regulation

For additional information on environmental regulation that may have a material impact on our business, see "Items 1. and 2. Business and Properties—Regulation and Environmental Matters."

### Related Party Transactions

The information required by this Item is included under "Item 8. Financial Statements and Supplementary Data—Note 13. Related Party Transactions" and "Item 13. Certain Relationships and Related Transactions, and Director Independence" in this Annual Report on Form 10-K and is incorporated by reference herein.

### Summary of Critical Accounting Estimates

Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See "Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies" in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significant accounting policies. The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates.

### Revenues

#### Mineral Rights Segment Revenues

*Royalty-based leases.* Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms. For these types of leases, the lessees generally make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral mined and sold. Most of our coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts, either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally range from three to five years.

We have defined our coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell our coal or aggregates over the lease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production would exceed consideration expected to be received from minimum payments over the lease term.

As a result of this evaluation, revenue recognition from our royalty-based leases is based on either production or minimum payments as follows:

- **Production Leases**: Leases for which we expect that consideration from production will be greater than consideration from minimums over the lease term. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, we recognize breakage revenue from minimums when we determine that recoupment is remote. This breakage revenue is included in production lease minimum revenues.
- **Minimum Leases**: Leases for which we expect that consideration from minimums will be greater than consideration from production over the lease term. Revenue for these leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues.

This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease.

Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenues from those sales. Also included within oil and gas royalty revenues are lease bonus payments, which are generally paid upon the execution of a lease. We also have overriding royalty revenue interests in certain of our coal and aggregates mineral rights. Revenue from these interests is recognized over time based on when the coal is sold.

*Carbon neutral initiative revenues.* Revenues related to consideration received from carbon neutral initiatives that are recognized at a point in time upon satisfaction of our performance obligation.

*Wheelage revenues.* Revenues related to fees collected per ton to transport foreign coal across property we own that is recognized over time as transportation across our property occurs.

*Other revenues.* Other revenues consist primarily of rental payments and surface damage fees related to certain land we own and are recognized straight-line over time as it is earned. Other revenues also include property tax revenues. The majority of property taxes paid on our properties are reimbursable by the lessee and are recognized on a gross basis over time which affects the reimbursement of property taxes by the lessee. Property taxes we pay are included in operating and maintenance expenses on our Consolidated Statements of Comprehensive Income (Loss).

*Transportation and processing services revenues.* We own transportation and processing infrastructure that is leased to third parties for throughput fees. Revenue is recognized over time based on the coal tons transported over the beltlines or processed through the facilities.

#### Contract Modifications

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

#### Contract Assets and Liabilities from Contracts with Customers

Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes unconditional. Receivables are recognized when the minimums are contractually owed, production occurs or minimums are accrued for based on the passage of time.

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

#### Equity in Earnings of Sisecam Wyoming.

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

### Mineral Rights

Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated economic tonnage as estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of our economic tonnage include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statistical analysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of economic tonnage, including many factors beyond our control. Estimates of economically recoverable tonnage depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results.

### Asset Impairment

We have developed procedures to evaluate our long-lived assets, including intangible assets, for possible impairment periodically or whenever events or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific events such as a reduction in economically recoverable tons or production ceasing on a property for an extended period. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the asset's net book value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants.

We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.

### Recent Accounting Standards

We do not believe that any other recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our financial statements.

## Market risk

As filed, 138 characters.

As a smaller reporting company for the year ended December 31, 2022, we are not required to include this disclosure in our 2022 Form 10-K.

## Controls and procedures

As filed, 6,528 characters.

### Evaluation of Disclosure Controls and Procedures

We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2022. This evaluation was performed under the supervision and with the participation 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, 2022 at the reasonable assurance level in producing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosures.

**Management’s Report on Internal Control Over Financial Reporting**

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2022 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, 2022, our management concluded that our internal control over financial reporting was effective at a reasonable assurance level based on those criteria. No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

### Report of Independent Registered Public Accounting Firm

The Partners of Natural Resource Partners L.P.

### Opinion on Internal Control Over Financial Reporting

We have audited Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Natural Resource Partners L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2022 and 2021, the related consolidated statements of comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and our report dated March 2, 2023 expressed an unqualified opinion thereon.

### Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

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

### Definition and Limitations of Internal Control Over Financial Reporting

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

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

/s/ Ernst & Young LLP

Houston, Texas

March 2, 2023

Filed Mar 3, 2023.
Source: SEC EDGAR, the filing index for accession 0001437749-23-005274. Last ingested by Listed: Nov 4, 2026, 12:57 ET. No prices; not investment advice.