Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||||
For the fiscal year ended December 31, 20212023 or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||||
For the transition period from to
Commission file number: 001-31465
NATURAL RESOURCE PARTNERS LP | ||||||||||||||||||||||
(Exact name of registrant as specified in its charter) | ||||||||||||||||||||||
Delaware | 35-2164875 | |||||||
(State or other jurisdiction of | (I.R.S. Employer | |||||||
1415 Louisiana Street, Suite 3400
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 751-7507
(Registrant’sRegistrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
| Common Units representing limited partner interests | NRP | New York Stock Exchange | ||||||||||||
Securities registered pursuant to Section 12(g) of the Act:
NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
☐ No ☒Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
☐ No ☒Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
☒ No ☐Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes
☒ No ☐Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition of "accelerated filer", "large accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer | ☐ | Accelerated Filer | ☒ | ||||||||||
Non-accelerated Filer | ☐ | Smaller Reporting Company | |||||||||||
Emerging Growth Company | ☐ | ||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☐Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report
☒If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yes
☐ No ☒The aggregate market value of the common units held by non-affiliates of the registrant on June 30, 2021, w
Documents incorporated by reference:
None.REGARDING FORWARD-LOOKING STATEMENTS
Statements included in this 10-K may constitute forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements. Such forward-looking statements include, among other things, statements regarding: the effects of the global COVID-19 pandemic;future distributions on our common and preferred units; our business strategy; our liquidity and access to capital and financing sources; our financial strategy; prices of and demand for coal, trona and soda ash, and other natural resources; estimated revenues, expenses and results of operations; projected production levels by our lessees; Sisecam Wyoming LLC’s ("Sisecam Wyoming's"), formerly known as Ciner Wyoming, trona mining and soda ash refinery operations; distributions from our soda ash joint venture; the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and global and U.S. economic conditions.
These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should not put undue reliance on any forward-looking statements. See "
Item 1A. Risk Factors" in this Annual Report on Form 10-K for important factors that could cause our actual results of operations or our actual financial condition to differ.We are subject to a variety of risks and uncertainties, including risks related to our business, risks related to our indebtedness, risks related to our common stockunits and certain general risks, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Risks that we deem material are described under “
Risks Related to Our Business
• | Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves. In addition, our debt agreements and our partnership agreement place restrictions on our ability to pay, and in some cases raise, the quarterly distribution under certain circumstances. |
• | Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. |
| • | Global pandemics, including the COVID-19 pandemic, have in the past and may continue to adversely affect our business. |
• | Prices for both metallurgical and thermal coal are volatile and depend on a number of factors beyond our control. Declines in prices could have a material adverse effect on our business and results of operations. |
• | Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Sisecam Wyoming’s ability to continue to make distributions to us. |
• | We derive a large percentage of our revenues and other income from a small number of coal lessees. |
• | Bankruptcies in the coal industry, and/or the idling or closure of mines on our properties could have a material adverse effect on our business and results of operations. |
• | Mining operations are subject to operating risks that could result in lower revenues to us. |
• | The adoption of climate change legislation and regulations restricting emissions of greenhouse gases and other hazardous air pollutants have resulted in changes in fuel consumption patterns by electric power generators and a corresponding decrease in coal production by our lessees and reduced coal-related revenues. |
• | Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending and investment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels. |
| • | Increased attention to climate change, environmental, social and governance ("ESG") matters and conservation measures may adversely impact our business. |
• | In addition to climate change and other Clean Air Act legislation, our businesses are subject to numerous other federal, state and local laws and regulations that may limit production from our properties and our profitability. |
• | If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease. |
• | We have limited approval rights with respect to the management of our Sisecam Wyoming soda ash joint venture, including with respect to cash distributions and capital expenditures. In addition, we are exposed to operating risks that we do not experience in the royalty business through our soda ash joint venture and through our ownership of certain coal transportation assets. |
| • | Sisecam Wyoming's deca stockpiles will substantially deplete by 2024, and its production rates will decline if Sisecam Wyoming does not make further investments or otherwise execute on one or more initiatives to prevent such decline. |
• | Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal, soda ash and other minerals from our properties. |
• | Our lessees could satisfy obligations to their customers with minerals from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments. |
• | A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period. |
Risks Related to Our Structure
• | Unitholders may not be able to remove our general partner even if they wish to do so. |
• | The preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future, which could result in substantial dilution of our common unitholders’ ownership interests. |
• | We may issue additional common units or preferred units without common unitholder approval, which would dilute a unitholder’s existing ownership interests. |
• | Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price. |
• | Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders. |
• | Conflicts of interest could arise among our general partner and us or the unitholders. |
• | The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements. |
• | Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business. |
Tax Risks to Common Unitholders
• | Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced. |
• | The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis. |
• | Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation. |
• | Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders' share of our portfolio income may be taxable to them even though they receive other losses from our activities. |
• | We may engage in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including income and gain from the sale of properties and cancellation of indebtedness income) allocable to our unitholders, and income tax liabilities arising therefrom may exceed any distributions made with respect to their units. |
• | If the IRS contests the U.S. federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders. |
• | If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced. |
• | Tax gain or loss on the disposition of our common units could be more or less than expected. |
• | Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. |
• | Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them. |
• | Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our units. |
• | We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units. |
• | We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units. |
• | We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. |
• | A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. |
• | As a result of investing in our units, our unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property. |
General Risks
• | Our business is subject to cybersecurity risks. |
Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may have an adverse effect on our business, financial condition, results of operations, and cash flows.
As used in this Part I,Annual Report on Form 10-K, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. 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").
We are a publicly traded Delaware limited partnership formed in 2002. We own, manage and lease a diversified portfolio of mineral properties in the United States, including interests in coal and other natural resources and own a no
Our business is organized into two operating segments:
Mineral Rights (formerly named Coal Royalty and Other segment)
Soda Ash
—consists of our 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining and soda ash production business located in the Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries.Our operations are conducted through Opco and our operating assets are owned by our subsidiaries. NRP (GP) LP, our general partner (the "general partner" or "NRP GP"), has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC (the "managing general partner"), conducts its business and operations and the Boardboard of Directorsdirectors and officers of GP Natural Resource Partners LLC make decisions on our behalf. Robertson Coal Management LLC ("RCM"), a limited liability company whollyindirectly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. SubjectPursuant to the Board Representation and Observation Rights Agreement entered into in 2017 with certain entities controlled by funds affiliated with Blackstone Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree"), Mr. Robertson, Jr. isBlackstone was entitled to appoint one person to the board of directors of GP Natural Resource Partners LLC (the "Board of Directors"). However, in 2023, we repurchased all of Blackstone's preferred units, which were subsequently retired and no longer remain outstanding, and all rights of Blackstone related thereto ceased as a result. In connection with the repurchase, Blackstone's board designee resigned from the Board of Directors and all members of the Board of Directors of GP Natural Resource Partners LLC and has delegated the right to appoint one director to Blackstone.
The senior executives and other officers who manage NRP are employees of Western Pocahontas Properties Limited Partnership or Quintana Minerals Corporation, which are companies controlled by Mr. Robertson, Jr. These officers allocate varying percentages of their time to managing our operations. Neither our general partner, GP Natural Resource Partners LLC, nor any of their affiliates receive any management fee or other compensation in connection with the management of our business, but they are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.
We have regional offices through which we conduct our operations, the largest of which is located at 5260 Irwin Road, Huntington, West Virginia 25705 and the telephone number is (304) 522-5757. Our principal executive office is located at 12011415 Louisiana Street, Suite 3400,3325, Houston, Texas 77002 and our telephone number is (713) 751-7507.
Segment and Geographic Information
The amount of 20212023 revenues and other income from our two operating segments is shown below. For additional business segment information, please see "
| (In thousands) | Amount | % of Total | ||||||||||||||||||||||||
| Mineral Rights | $ | 194,493 | 90% | |||||||||||||||||||||||
| Soda Ash | 21,871 | 10% | ||||||||||||||||||||||||
| Total | $ | 216,364 | 100% | |||||||||||||||||||||||
(In thousands) | Amount | % of Total | ||||||
Mineral Rights | $ | 296,612 | 80 | % | ||||
Soda Ash | 73,397 | 20 | % | |||||
Total | $ | 370,009 | 100 | % | ||||
The following map shows the approximate geographic distribution of our ownership footprint:
Mineral Rights Segment
Mineral Rights
We do not mine, drill or produce minerals. Instead, we lease our acreage to companies engaged in the extraction of minerals in exchange for the payment of royalties and various other fees. The royalties we receive are generally a percentage of the gross revenue received by our lessees. The royalties we receive are typically supported by a floor price and minimum payment obligation that protect us during significant price or demand declines.
The majority of our Mineral Rights segment revenues come from royalties related to the sale of coal from our properties. Our coal is primarily located in the Appalachia Basin, the Illinois Basin and the Northern Powder River Basin in the United States. We lease our coal to experienced mine operators under long-term leases. Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms. Leases include the right to renegotiate royalties and minimum payments for the additional terms. We also own and manage coal-related transportation and processing assets in the Illinois Basin that generate additional revenues generally based on throughput or rents. We also own oil and gas, industrial minerals and aggregates that generate a portion of the Mineral Rights segment revenues.
Under our standard royalty lease, we grant the operators the right to mine and sell our coalminerals in exchange for royalty payments based on the greater of a percentage of the sale price or fixed royalty per ton of minerals mined and sold. Lessees calculate royalty payments due to us and are required to report tons of minerals mined and sold as well as the sales prices of the extracted minerals. Therefore, to a great extent, amounts reported as royalty revenues are based upon the reports of our lessees. We periodically audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify that the information that our lessees have submitted to us is accurate. Our audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to us and the actual results from each property.
In addition to their royalty obligations, our lessees are often subject to minimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. Minimum payments are usually credited against future royalties that are earned as minerals are produced. In certain leases, the lessee is time limited on the period available for recouping minimum payments and such time is unlimited on other leases.
Because we do not operate, any coal mines, our coal royalty business does not bear ordinary operating costs and has limited direct exposure to environmental, permitting and labor risks. Our lessees, as operators, are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. In addition, the lessees generally bear all labor-related risks, including retiree health care costs, black lung benefits and workers’ compensation costs associated with operating the mines on our coal and aggregates properties. We pay property taxes on our properties, which are largely reimbursed by our lessees pursuant to the terms of the various lease agreements.
The SEC has adopted new rules to modernizeamended the property disclosure requirements for registrants with significant mining activities, effective for the fiscal year 2021, with new rules which we have to comply with in this Annual Report on Form 10-K. The new rules contain exceptions that allow royalty companies, such as NRP, to omit information that they lack access to and cannot obtain without incurring an unreasonable burden or expense. As a royalty company, we do not have access to the information required to prepare the technical reports used to determine reserves under the new rules, and we are not able to obtain such information without unreasonable burden or expense. The new rules require that reserve estimates be based on and disclosures include technical reports prepared using extensive mine-specific geological and engineering data, as well as market and cost assumptions that we as a mineral owner do not have, include,including, but are not limited to a) site infrastructure costs; b) processing plant costs; c) detailed analysis of environmental compliance and permitting requirements; d) detailed baseline studies with impact assessment; and e) detailed tailings disposal, reclamation and mitigation plans. Our leases do not require the operators of our material properties to prepare technical report summaries or permit us the access and information sufficient to prepare our own technical report summaries under the new rules. As a result, we are relying on the royalty company exceptions and have ceased to report coal and other hard mineral reserves in this Annual Report on Form 10-K.
In addition to summary information about our overall portfolio of mineral rights, this section provides detailed information about four properties in our Mineral Rights segment. These properties were determined to be material to our business based on historical revenue compared to our Mineral Rights segment considered as a whole. These four properties are: 1) Alpha-CAPP (VA), 2) Oak Grove, 3) Williamson, and 4) Hillsboro. We have also included a description of other significant properties, which have had lower revenues historically than our material properties but are important to our business.
Coal
Metallurgical Coal
Metallurgical (“Met”) coal is used to fuel blast furnaces that forge steel and is the primary driver of our long-term cash flows. Met coal is a high-quality, cleaner coal that generates exceptionally high temperatures when burned and is an essential element in the steel manufacturing process. Metallurgical coal is a finite and declining resource, particularly in industrialized nations. We believe the indispensable role met coal plays in manufacturing steel combined with the increasing scarcity of the resource will provide support for this portion of our business for decades to come. Our metallurgical coal is located in the Northern, Central and Southern Appalachian regions of the United States.
Thermal Coal
Thermal coal, sometimes referred to as steam coal, is used in the production of electricity. The amount of thermal coal produced in the United States has been steadily falling over the last decade as energy providers shift from coal-fired plants to natural gas-fired facilities, and to a lesser extent, alternative energy sources such as geothermal, wind and solar. We believe the long-term secular decline experienced by thermal coal over the last decade will continue. That fact, combined with the long-term strength of our metallurgical business and the carbon neutral initiatives we discuss below, will result in thermal coal becoming a diminishing contributor to NRP in years to come. The vast majority of our thermal sales are located in Illinois and its operations are some of the most cost-efficient mines east of the Mississippi River. The remainder of our thermal coal is located in Montana, the Gulf Coast and Appalachia.
The following tables present the type of coal sales volumes by major coal region for the years ended December 31, 2021, 20202023, 2022 and 2019:
| For the Year Ended December 31, 2021 | ||||||||||||||||||||
| Type of Coal | ||||||||||||||||||||
| (Tons in thousands) | Thermal | Metallurgical | Total | |||||||||||||||||
| Appalachia Basin | ||||||||||||||||||||
| Northern | 718 | 617 | 1,335 | |||||||||||||||||
| Central | 1,140 | 11,139 | 12,279 | |||||||||||||||||
| Southern | 119 | 1,452 | 1,571 | |||||||||||||||||
| Total Appalachia Basin | 1,977 | 13,208 | 15,185 | |||||||||||||||||
| Illinois Basin | 9,388 | — | 9,388 | |||||||||||||||||
| Northern Powder River Basin | 3,151 | — | 3,151 | |||||||||||||||||
| Gulf Coast | 55 | — | 55 | |||||||||||||||||
| Total | 14,571 | 13,208 | 27,779 | |||||||||||||||||
| For the Year Ended December 31, 2020 | ||||||||||||||||||||
| Type of Coal | ||||||||||||||||||||
| (Tons in thousands) | Thermal | Metallurgical | Total | |||||||||||||||||
| Appalachia Basin | ||||||||||||||||||||
| Northern | 267 | 380 | 647 | |||||||||||||||||
| Central | 1,157 | 8,954 | 10,111 | |||||||||||||||||
| Southern | 143 | 746 | 889 | |||||||||||||||||
| Total Appalachia Basin | 1,567 | 10,080 | 11,647 | |||||||||||||||||
| Illinois Basin | 3,381 | — | 3,381 | |||||||||||||||||
| Northern Powder River Basin | 1,738 | — | 1,738 | |||||||||||||||||
| Total | 6,686 | 10,080 | 16,766 | |||||||||||||||||
| For the Year Ended December 31, 2019 | ||||||||||||||||||||
| Type of Coal | ||||||||||||||||||||
| (Tons in thousands) | Thermal | Metallurgical | Total | |||||||||||||||||
| Appalachia Basin | ||||||||||||||||||||
| Northern | 2,781 | 679 | 3,460 | |||||||||||||||||
| Central | 3,117 | 10,260 | 13,377 | |||||||||||||||||
| Southern | 470 | 1,200 | 1,670 | |||||||||||||||||
| Total Appalachia Basin | 6,368 | 12,139 | 18,507 | |||||||||||||||||
| Illinois Basin | 2,201 | — | 2,201 | |||||||||||||||||
| Northern Powder River Basin | 3,036 | — | 3,036 | |||||||||||||||||
| Total | 11,605 | 12,139 | 23,744 | |||||||||||||||||
For the Year Ended December 31, 2023 | ||||||||||||
Type of Coal | ||||||||||||
(Tons in thousands) | Thermal | Metallurgical | Total | |||||||||
Appalachia Basin | ||||||||||||
Northern | 794 | 351 | 1,145 | |||||||||
Central | 1,418 | 12,509 | 13,927 | |||||||||
Southern | — | 2,670 | 2,670 | |||||||||
Total Appalachia Basin | 2,212 | 15,530 | 17,742 | |||||||||
Illinois Basin | 8,119 | — | 8,119 | |||||||||
Northern Powder River Basin | 4,589 | — | 4,589 | |||||||||
Gulf Coast | 1,477 | — | 1,477 | |||||||||
Total | 16,397 | 15,530 | 31,927 | |||||||||
For the Year Ended December 31, 2022 | ||||||||||||
Type of Coal | ||||||||||||
(Tons in thousands) | Thermal | Metallurgical | Total | |||||||||
Appalachia Basin | ||||||||||||
Northern | 1,166 | 530 | 1,696 | |||||||||
Central | 1,186 | 12,460 | 13,646 | |||||||||
Southern | 93 | 1,691 | �� | 1,784 | ||||||||
Total Appalachia Basin | 2,445 | 14,681 | 17,126 | |||||||||
Illinois Basin | 11,135 | — | 11,135 | |||||||||
Northern Powder River Basin | 4,288 | — | 4,288 | |||||||||
Gulf Coast | 385 | — | 385 | |||||||||
Total | 18,253 | 14,681 | 32,934 | |||||||||
For the Year Ended December 31, 2021 | ||||||||||||
Type of Coal | ||||||||||||
(Tons in thousands) | Thermal | Metallurgical | Total | |||||||||
Appalachia Basin | ||||||||||||
Northern | 718 | 617 | 1,335 | |||||||||
Central | 1,140 | 11,139 | 12,279 | |||||||||
Southern | 119 | 1,452 | 1,571 | |||||||||
Total Appalachia Basin | 1,977 | 13,208 | 15,185 | |||||||||
Illinois Basin | 9,388 | — | 9,388 | |||||||||
Northern Powder River Basin | 3,151 | — | 3,151 | |||||||||
Gulf Coast | 55 | 55 | ||||||||||
Total | 14,571 | 13,208 | 27,779 | |||||||||
Major Coal Producing Properties
The following table provides a summary of our significant coal royalty properties by sales volumes for 20212023 and is followed by additional information for each property:
Region | Property/Lease Name | Operator(s) | Coal Type | |||||||||||||||||||||||
Appalachia Basin | ||||||||||||||||||||||||||
Central | ||||||||||||||||||||||||||
Alpha-CAPP (VA) | Alpha Metallurgical Resources Inc. | Met | ||||||||||||||||||||||||
Central | Kepler | Alpha Metallurgical Resources Inc. | Met | |||||||||||||||||||||||
Central | Elk Creek | Ramaco Royalty Company, LLC | Met | |||||||||||||||||||||||
Central | Coal Mountain | ECP | Met | |||||||||||||||||||||||
Southern | ||||||||||||||||||||||||||
Oak Grove | Hatfield Metallurgical Coal Holdings, LLC | Met | ||||||||||||||||||||||||
Illinois Basin | Williamson | Foresight Energy Resources LLC | Thermal | |||||||||||||||||||||||
Illinois Basin | Hillsboro | Foresight Energy Resources LLC | Thermal | |||||||||||||||||||||||
Northern Powder River Basin | Western Energy | Rosebud Mining, LLC | Thermal | |||||||||||||||||||||||
Alpha-CAPP (VA).
The Alpha-CAPP (VA) property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia.Below is a map of our Alpha-CAPP (VA) property:
Elk Creek.
The Elk Creek property is located in Logan and Wyoming Counties, West Virginia.Coal Mountain.
The Coal Mountain property is located in Wyoming County, West Virginia.Kepler
. The Kepler property is located in Wyoming County, West Virginia.Oak Grove
. The Oak Grove property is located in Jefferson County, Alabama.Below is a map of our Oak Grove property:
Williamson.
The Williamson property is located in Franklin and Williamson Counties, Illinois. This property is under leases to Williamson Energy, a subsidiary of Foresight Energy Resources LLC ("Foresight"). The current leases expire in 2026 and 2033 andBelow is a map of our Williamson property:
Hillsboro.The Hillsboro property is located in Montgomery and Bond Counties, Illinois. This property is under lease to Hillsboro Energy, a subsidiary of Foresight. The current lease expires in 2033 and Hillsboro Energy will have the option toautomatically renew the lease upon the expiration of its current term.unless otherwise notified. We receive payments based on the greater of a percentage of the sale price or fixed royalty per ton of coal mined and sold. In addition to the royalty obligations, this lease is subject to non-recoupable minimum payments, which reflect amounts we are entitled to receive even if no mining activity occurs during the period. In 2021, approximately 3.7 million tons of thermalThermal coal were sold from this property. Productionproduction comes from a longwall mine. Coal is shipped by rail via either the Union Pacific, Norfolk Southern or Canadian National railroads, or by barges to domestic utilities customers. The book value of this property was $224.6$209.3 million at December 31, 2021.
Below is a map of our Hillsboro property:
In addition to these properties, we own loadout and other transportation assets at the Williamson mine and at the Macoupin and Sugar Camp mines, which are also operated by Foresight. See "—Coal Transportation and Processing Assets" below for additional information on these assets.
Production at the Foresight Macoupin mine was temporarily ceased in March 2020. Pursuant to the Master Agreement, Foresight is no longer obligated to make royalty, transportation fee, or quarterly minimum payments to us under the Macoupin coal mining lease and transportation agreements. Foresight will instead pay an annual Macoupin fee of $2.0 million to NRP each year through 2023. The amounts paid for 2021 are included in the fixed amounts discussed in the paragraph above.2026. Foresight also forfeited its right to recoup all previously paid but unrecouped minimum payments with respect to the Macoupin mine. At all times that the Macoupin mine remains in temporary cessation of production, Foresight will take reasonable actions to preserve, protect, and store the equipment, infrastructure, and property located at the mine.
Beginning January 1, 2024,2027, we may at any time elect to cause Foresight to transfer the Macoupin mine and all associated equipment and permits to us for no consideration. If we make this election, we will assume all liabilities associated with the Macoupin mine. Also beginning January 1, 2024,2027, Foresight may at any time elect to offer to sell the Macoupin assets to us for $1.00. If we accept Foresight’s offer, we will assume all liabilities associated with the Macoupin mine. If we do not accept Foresight’s offer, Foresight may proceed to permanently seal the Macoupin mine and conduct all reclamation activities. To the extent the elections described above are not made, Foresight will continue to pay the annual $2.0 million fee to NRP each year that the mine remains in temporary cessation of production. In addition, Foresight may determine at any time to recommence operations at the Macoupin mine, at which time we and Foresight will negotiate in good faith to enter into new coal mining lease and transportation agreements.agreements applicable to the Macoupin mine.
Western Energy.
The Western Energy property is located in Rosebud and Treasure Counties, Montana.Coal Transportation and Processing Assets
We own transportation and processing infrastructure related to certain of our coal properties, including loadout and other transportation assets at Foresight's Williamson and Macoupin minesmine in the Illinois Basin, for which we collect throughput fees or rents. We lease our Macoupin and Williamson transportation and processing infrastructure to subsidiariesa subsidiary of Foresight and are responsible for operating and maintaining the transportation and processing assets at the Williamson mine that we subcontract to a subsidiary of Foresight. In addition, we own rail loadout and associated infrastructure at the Sugar Camp mine, an Illinois Basin mine also operated by a subsidiary of Foresight. While we own coal at the Williamson and Macoupin mines,mine, we do not own coal at the Sugar Camp mine. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight and we collect minimums and throughput fees. We recorded $9.1$14.9 million in revenue related to our coal transportation and processing assets during the year ended December 31, 2021. Production2023.
We also own transportation and processing infrastructure, including loadout and other transportation assets at Foresight's Macoupin mine. As previously mentioned, the Macoupin mine was temporarily ceased in March 2020 and in June 2020, we and Foresight entered into a Master Agreement in connection with Foresight’s emergence from bankruptcy as discussed above.
Oil and Gas / Industrial Minerals / Construction Aggregates / Timber
Our oil and gas properties are predominately located in Louisiana.Louisiana and during 2023, we received $7.4 million in oil and gas royalty revenues. Our various industrial mineral and construction aggregates properties are located across the United States and include minerals such as limestone, frac sand, lithium, copper, lead and zinc. We lease a portion of these minerals to third parties in exchange for royalty payments. The structure of these leases is similar to our coal leases, and these leases typically require minimum rental payments in addition to royalties. During 2021,2023, we received $1.9$2.9 million inin aggregates royalty revenues, including overriding royalty revenues. We also own forest assets, primarily in West Virginia, which generate revenues from the forestland through carbon offset credits and timber sales.
Carbon Neutral Initiatives
We continue to explore and identify alternative carbon neutral revenue sources across our large portfolio of land,surface, mineral, and timber assets. The types of opportunities includeassets, including the permanent sequestration of carbon dioxide ("CO2") underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy.energy, as well as lithium production. As with our existing mineral activities, we do not plan to develop or operate carbon sequestration or carbon neutral energy projects ourselves but we plan to lease our acreage to companies that will conduct those operations in exchange for payment of royalties and other fees to us.
We executed our first carbon neutral project in the fourth quarter of 2021 through the sale of 1.1 million carbon offset credits for $13.8 million. The offset credits were issued to us by the California Air Resources Board under its cap-and-trade program and represent 1.1 million tonnesmetric tons of carbon sequestered in approximately 39,000 acres of our forestland in West Virginia. This is an encouraging first step in ourWe have the ability to create value through alternative revenue sources.
Carbon Sequestration.
We own approximately 3.5 million acres of specifically reserved subsurface rights in the southern United States with the potential for permanent sequestration of greenhouse gases. The carbon capture utilization and storage industry (“CCUS”) is in its infancy and the future is highly uncertain, but a few facts are clear. A sequestration project requires acreage possessing unique geologic characteristics, close proximity to sources of industrial-scale greenhouse gas emissions or direct air capture capability, and the appropriate form of legal title that grants the acreage owner the right to sequester emissions in the subsurface. While carbon sequestration rights and ownership continue to evolve, we believe we own one of the largest inventory of acreage with potential for carbon sequestration activities in the United States.In Februarythe first quarter of 2022 we announced the execution of a CO
Renewable Energy.
In addition,We own a 49% non-controlling equity interest in Sisecam Wyoming. Prior to 2023, Sisecam Resources LP (formerly know as Cinerowned 51% interest in Sisecam Wyoming. Sisecam Resources LP)LP was a publicly traded master limited partnership that depended on distributions from Sisecam Wyoming in order to make distributions to its public unitholders. In 2023, Sisecam Resources LP was dissolved and Sisecam Chemicals Wyoming LLC ("SCW LLC") became the direct owner of 51% of Sisecam Wyoming. SCW LLC, our operating partner, ("Sisecam Resources"), controls and operates Sisecam Wyoming. SCW LLC is 100% owned by Sisecam Chemicals Resources LLC ("Sisecam Chemicals,") which is 60% owned by Sisecam USA Inc. ("Sisecam USA") and 40% owned by Ciner Enterprises Inc. ("Ciner Enterprises"). Sisecam USA is a direct wholly-owned subsidiary of Türkiye Şişe ve Cam Fabrikalari A.Ş, a Turkish Corporation ("Şişecam Parent"), which is an approximately 51%-owned subsidiary of Turkiye Is Bankasi Turkiye Is Bankasi ("Isbank"). Şişecam Parent is a global company operating in soda ash, chromium chemicals, flat glass, auto glass, glassware glass packaging and glass fiber sectors. Şişecam Parent was founded over 88 years ago, is based in Turkey and is one of the largest industrial publicly-listed companies on the Istanbul exchange. With production facilities in several continents and in several countries, Sisecam is one of the largest glass and chemicals producers in the world. Ciner Enterprises is a direct wholly-owned subsidiary of WE Soda Ltd., a U.K. Corporation (“WE Soda”). WE Soda is a direct wholly-owned subsidiary of KEW Soda Ltd., a U.K. corporation (“KEW Soda”), which is a direct wholly owned subsidiary of Akkan Enerji ve Madencilik Anonim Şirketi (“Akkan”). Akkan is directly and wholly owned by Turgay Ciner, the Chairman of the Ciner Group (“Ciner Group”), a Turkish conglomerate of companies engaged in energy and mining (including soda ash mining), media and shipping markets. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries. Sisecam Resources is a publicly traded master limited partnership that depends on distributions from Sisecam Wyoming in order to make distributions to its public unitholders. As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine or soda ash production plant. We appoint three of the seven members of the Board of Managers of Sisecam Wyoming and have certain limited negative controls relating to the company. We have limited approval rights with respect to Sisecam Wyoming, and our partner controls most business decisions, including decisions with respect to distributions and capital expenditures. During 2020, Sisecam Wyoming suspended cash distributions to its members due to adverse developments in the soda ash market resulting from the COVID-19 pandemic. In 2021, as soda ash markets improved, Sisecam Wyoming resumed distributions with respect to the third quarter; however, distributions may again be suspended in the future.
Sisecam Wyoming is one of the largest and lowest cost producers of soda ash in the world, serving a global market from its facility located in the Green River Basin of Wyoming. The Green River Basin geological formation holds the largest, and one of the highest purity, known deposits of trona ore in the world. Trona, a naturally occurring soft mineral, is also known as sodium sesquicarbonate and consists primarily of sodium carbonate, or soda ash, sodium bicarbonate and water. Sisecam Wyoming processes trona ore into soda ash, which is an essential raw material in flat glass, container glass, detergents, chemicals, paper and other consumer and industrial products. The vast majority of the world’s accessible trona is located in the Green River Basin. According to historical production statistics, approximately 30% of global soda ash is produced by processing trona, with the remainder being produced synthetically through chemical processes. The costs associated with procuring the materials needed for synthetic production are greater than the costs associated with mining trona for trona-based production. In addition, trona-based production consumes less energy and produces fewer undesirable by-products than synthetic production.
Sisecam Wyoming’s Green River Basin surface operations are situated on approximately 2,360 acres in Wyoming (of which, 880 acres are owned by Sisecam Wyoming), and its mining operations consist of approximately 23,500 acres of leased and licensed subsurface mining area.areas in Wyoming. The facility is accessible by both road and rail. Sisecam Wyoming uses seven large continuous mining machines and 14 underground shuttle cars in its mining operations. Its processing assets consist primarily of material sizing units, conveyors, calciners, dissolver circuits, thickener tanks, drum filters, evaporators and rotary dryers.
In trona ore processing, insoluble materials and other impurities are removed by thickening and filtering liquor, a solution consisting of sodium carbonate dissolved in water. Sisecam Wyoming then adds activated carbon to filters to remove organic impurities, which can cause color contamination in the final product. The resulting clear liquid is then crystallized in evaporators, producing sodium carbonate monohydrate. The crystals are then drawn off and passed through a centrifuge to remove excess water. The resulting material is dried in a product dryer to form anhydrous sodium carbonate, or soda ash. The resulting processed soda ash is then stored in on-site storage silos to await shipment by bulk rail or truck to distributors and end customers. Sisecam Wyoming’s storage silos can hold over 58,000 short tons of processed soda ash at any given time. The facility is in good working condition and has been in service for more than 5060 years.
Deca Rehydration.
Shipping and Logistics.
For the year ended December 31, 2023, Sisecam Wyoming assisted the majority of its domestic customers in arranging their freight services.All of the soda ash produced is shipped by rail or truck from the Green River Basin facility. For the year ended December 31,Customers. Sisecam Wyoming's largest customer was ANSAC for the year ended December 31, 2021 and the sales to ANSAC accounted forWyoming generated approximately 21%half of its net sales. The significant volumegross revenue from export sales, which consist of sales to ANSAC for the year ended December 31, 2021 was primarily related to the terms of the ANSAC exit settlement agreement. No other individual customer accounted for more than 10% of Sisecam Wyoming's net sales.
Sisecam Wyoming’s customers including end users to whom ANSAC makes sales overseas, consist primarily of glass manufacturing companies, which account for 50% or more of the consumption of soda ash around the world;world, and chemical and detergent manufacturing companies.
Sisecam Chemical Resources’ exit from ANSAC, ANSAC managed most of Sisecam Wyoming'sChemicals has now completed three full years directly managing its international sales, marketing and logistics and as a result, was its largest customer foractivities since exiting ANSAC at the years ended December 31, 2020 and 2019, accounting for 45% and 60%, respectively,end of its net sales. ANSAC takes soda ash orders directly from its overseas customers and then purchases soda ash for resale from its member companies pro rata based on each member’s allocated volumes. ANSAC is the exclusive distributor for its members to the markets it serves. The ANSAC exit allowed2020. Sisecam Chemical ResourcesChemicals took direct control of these activities to improve access to customers and gain control over placement of its sales in the international marketplace in 2021.marketplace. This enhanced view of the global market allows Sisecam Chemical ResourcesChemicals to better understand supply/demand fundamentals thus allowing better decision making for its business. Sisecam Chemical ResourcesChemicals continues to optimize its distribution network leveraging strengths of existing distribution partners while expanding as theits business requires in certain target areas.
Leases and License.
Sisecam Wyoming is party to several mining leases and one license for its subsurface mining rights. Some of the leases are renewable at Sisecam Wyoming’s option upon expiration. Sisecam Wyoming pays royalties to the State of Wyoming, the U.S. Bureau of Land Management and Sweetwater Royalties LLC, a subsidiary of Sweetwater Trona OpCo LLC and the successor in interest to the license with the Rock Springs Royalty Company LLC, an affiliate of Occidental Petroleum Corporation (formerly an affiliate of Anadarko Petroleum Corporation)As a minority interest owner in Sisecam Wyoming, we do not operate and are not involved in the day-to-day operation of the trona ore mine or soda ash production plant. Our partner, Sisecam Resources,SCW, manages the mining and plant operations. We appoint three of the seven members of the Board of Managers of Sisecam Wyoming and have certain limited negative controls relating to the company.
Significant Customers
We have a significant concentration of revenues from Alpha, with total revenues of $86.1
Competition
We face competition from land companies, coal producers, international steel companies and private equity firms in purchasing coal and royalty producing properties. Numerous producers in the coal industry make coal marketing intensely competitive. Our lessees compete among themselves and with coal producers in various regions of the United States for domestic sales. Lessees compete with both large and small producers nationwide on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity and steel, as well as government regulations, technological developments and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, wind, solar and hydroelectric power.
Sisecam Wyoming's trona mining and soda ash refinery business faces competition from a number of soda ash producers in the United States, Europe and Asia, some of which have greater market share and greater financial, production and other resources than Sisecam Wyoming does. Some of Sisecam Wyoming’s competitors are diversified global corporations that have many lines of business and some have greater capital resources and may be in a better position to withstand a long-term deterioration in the soda ash market. Other competitors, even if smaller in size, may have greater experience and stronger relationships in their local markets. Competitive pressures could make it more difficult for Sisecam Wyoming to retain its existing customers and attract new customers, and could also intensify the negative impact of factors that decrease demand for soda ash in the markets it serves, such as adverse economic conditions, weather, higher fuel costs and taxes or other
Title to Property
We owned substantially all of our coal and aggregates mineral rights in fee as of December 31, 2021.2023. We lease the remainder from unaffiliated third parties. Sisecam Wyoming leases or licenses its trona. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operation of our business.
For most of our properties, the surface, oil and gas and mineral or coal estates are not owned by the same entities. Some of those entities are our affiliates. State law and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the existence of the severed estates will materially impede development of the minerals on our properties.
General
Operations on our properties must be conducted in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls ("PCBs"). Because of extensive, comprehensive and often ambiguous regulatory requirements, violations during natural resource extraction operations are not unusual and, notwithstanding compliance efforts, we do not believe violations can be eliminated entirely.
While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations, those costs have been and are expected to continue to be significant. Our lessees in our coal and aggregates royalty businesses are required to post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closures, including the cost of treating mine water discharge when necessary. In many states our lessees also pay taxes into reclamation funds that states use to achieve reclamation where site specific performance bonds are inadequate to do so. Determinations by federal or state agencies that site specific bonds or state reclamation funds are inadequate could result in increased bonding costs for our lessees or even a cessation of operations if adequate levels of bonding cannot be maintained. We do not accrue for reclamation costs because our lessees are both contractually liable and liable under the permits they hold for all costs relating to their mining operations, including the costs of reclamation and mine closures. Although the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. In recent years, compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.
In addition, the electric utility industry, which is the most significant end-user of thermal coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which has affected and is expected to continue to affect demand for coal mined from our properties. Current and future proposed legislation and regulations could be adopted that will have a significant additional impact on the mining operations of our lessees or their customers’ ability to use coal and may require our lessees or their customers to change operations significantly or incur additional substantial costs that would negatively impact the coal industry.
Many of the statutes discussed below also apply to Sisecam Wyoming’s trona mining and soda ash production operations, and therefore we do not present a separate discussion of statutes related to those activities, except where appropriate.
Air Emissions
The Clean Air Act and corresponding state and local laws and regulations affect all aspects of our business. The Clean Air Act directly impacts our lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of federal rulemakings that are focused on emissions from coal-fired electric generating facilities, including the Cross-State Air Pollution Rule ("CSAPR"), regulating emissions of nitrogen oxide ("NOx") and sulfur dioxide, and the Mercury and Air Toxics Rule ("MATS"), regulating emissions of hazardous air pollutants. In March 2021, the U.S. Environmental Protection Agency ("EPA") revised the CSAPR to require additional emissions reductions of nitrogen oxideNOx from power plants in twelve states. Further, in April 2022, EPA published a proposed rule to build on the CSAPR by imposing Federal Implementation Plans on over 20 states to implement the National Ambient Air Quality Standards ("NAAQS") for ozone. However, on August 21, 2023, the EPA announced a new review of the ozone NAAQS in combination with its reconsideration of EPA's December 2020 decision to retain the 2015 NAAQS. The EPA is expected to release its Integrated Review Plan in the fall of 2024. Installation of additional emissions control technologies and other measures required under EPA regulations make it more costly to operate coal-fired power plants and could make coal a less attractive or even effectively prohibited fuel source in the planning, building and operation of power plants in the future. These rules and regulations have resulted in a reduction in coal’s share of power generating capacity, which has negatively impacted our lessees’ ability to sell coal and our coal-related revenues. Further reductions in coal’s share of power generating capacity as a result of compliance with existing or proposed rules and regulations would have a material adverse effect on our coal-related revenues.
The EPA’s regulation of methane under the Clean Air Act may also affect oil and gas production on properties in which we hold oil and gas interests. In December 2023, the EPA issued its methane rules, known as OOOOb and OOOOc, that establish new source and first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. We are unable to predict at this time the impact of these requirements on any such oil and gas production on our properties.
In December 2009, EPA determined that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and welfare because emissions of such gases are, according to EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on its findings, EPA began adopting and implementing regulations to restrict emissions of GHGs under various provisions of the Clean Air Act.
In August 2015, EPA published its final Clean Power Plan ("CPP") Rule, a multi-factor plan designed to cut carbon pollution from existing power plants, including coal-fired power plants. The rule required improving the heat rate of existing coal-fired power plants and substituting lower carbon-emission sources like natural gas and renewables in place of coal. As promulgated, the rule would force many existing coal-fired power plants to incur substantial costs in order to comply or alternatively result in the closure of some of these plants, likely resulting in a material adverse effect on the demand for coal by electric power generators. The rule was being challenged by several states, industry participants and other parties in the United States Court of Appeals for the District of Columbia Circuit. In February 2016, the Supreme Court of the United States stayed the CPP Rule pending a decision by the District of Columbia Circuit as well as any subsequent review by the Supreme Court. In April 2017, the United States Court of Appeals for the District of Columbia Circuit granted EPA’s motion to hold the litigation in abeyance. In December 2017, EPA issued a proposed rule repealing the CPP Rule and issued an Advance Notice of Proposed Rulemaking soliciting information regarding a potential replacement rule to the CPP Rule. In August 2018, EPA formally proposed the Affordable Clean Energy ("ACE") Rule, which would replace the CPP Rule. The ACE Rule contemplates a narrower approach than the CPP Rule, focusing on efficiency improvements at existing power plants and eliminating the CPP Rule’s broader goals that envisioned switches to non-fossil fuel energy sources and the implementation of efficiency measures on demand-side entities, which the EPA now considers beyond the reach of its authority under the Clean Air Act. The ACE Rule would also omit specific numerical emissions targets that had been established under the CPP Rule. The ACE Rule went into effect on September 6, 2019. As a result, the United States Court of Appeals for the District of Columbia Circuit dismissed the pending challenges to the CPP Rule as moot. The ACE Rule was challenged by public health groups, environmental groups, states, municipalities, industry groups, and power providers. The legal challenges were consolidated as
American Lung Assoc. v. EPA before the D.C. Circuit Court of Appeals. Dozens of parties and over 170 amici filed briefs on the merits, and oral argument was held before a three-judge panel in October 2020. In January 2021, the D.C. Circuit issued a written opinion holding that the ACE Rule was based on EPA’s “erroneous legal premise” that when it determines the “best system of emission reduction” for existing sources, the Clean Air Act mandates that EPA may only consider emission reduction measures that can be applied at and/or to a stationary source (often referred to as “inside-the-fence” measures). The Court vacatedIn October 2015, EPA published its final rule on performance standards for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The final rule requires new steam generating units to use highly efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture and storage technology. The final emission standard is less stringent than EPA had originally proposed due to updated cost assumptions, but could still have a material adverse effect on new coal-fired power plants. The final rule has been challenged by several states, industry participants and
Certain authorizations required for certain mining and oil and gas operations may be difficult to obtain or use due to challenges from environmental advocacy groups to the environmental analyses conducted by federal agencies before granting permits. In particular, those approvals necessary for certain coal activities that are subject to the requirements of the National Environmental Policy Act (“NEPA”) are subject to real uncertainty. In April 2022, the Council on Environmental Quality (“CEQ”) issued a final rule, which is considered “Phase I” of the Biden Administration’s two-phased approach to modifying the NEPA, revoking some of the modifications made to the NEPA regulations under the previous administration and reincorporating the consideration of direct, indirect, and cumulative effects of major federal actions, including GHG emissions. In July 2023, the CEQ announced a “Phase 2” Notice of Proposed Rulemaking, the “Bipartisan Permitting Reform Implementation Rule,” which revises the implementing regulations of the procedural provisions of NEPA and implements the amendments to NEPA included in the June 3, 2023, Fiscal Responsibility Act of 2023. The final rule is expected in 2024. If any mining, or oil and gas operations are subject to permitting requirements that trigger NEPA, there is likely to be some uncertainty about the viability of any approvals that our lessees may obtain.
In November 2014, President Obama also announced an emission reduction agreement with China’s President Xi Jinping in November 2014.Jinping. The United States pledged that by 2025 it would cut climate pollution by 26% to 28% from 2005 levels. China pledged it would reach its peak carbon dioxide emissions around 2030 or earlier, and increase its non-fossil fuel share of energy to around 20% by 2030. In December 2015, the United States was one of 196 countries that participated in the Paris Climate Conference, at which the participants agreed to limit their emissions in order to limit global warming to 2°C above pre-industrial levels, with an aspirational goal of 1.5°C. While there is no way to estimate the impact of these climate pledges and agreements, including, most recently, the 28th session of the United Nations Conference of the Parties ("COP28") in December 2023, they could ultimately have an adverse effect on the demand for coal, both nationally and internationally, if implemented. In 2019, President Trump withdrew from the Paris Climate Agreement. On February 19, 2021, the United States officially rejoined the Paris Climate Agreement per President Biden’s order signed January 20. Additionally, at COP28, the parties signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly and equitable manner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for reaching net zero by that date was set.
The Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or the Superfund law) and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to haveresponsible for having contributed to the release of a “hazardous substance” into the environment. We could become liable under federal and state Superfund and waste management statutes if our lessees are unable to pay environmental cleanup costs relating to hazardous substances. In addition, we may have liability for environmental clean-up costs in connection with Sisecam Wyoming's soda ash businesses.
Water Discharges
Operations conducted on our properties can result in discharges of pollutants into waters. The Clean Water Act and analogous state laws and regulations create two permitting programs for mining operations. The National Pollutant Discharge Elimination System (NPDES)("NPDES") program under Section 402 of the statute is administered by the states or EPA and regulates the concentrations of pollutants in discharges of waste and storm water from a mine site. The Section 404 program is administered by the Army Corps of Engineers and regulates the placement of overburden and fill material into channels, streams and wetlands that comprise “waters of the United States.” The scope of waters that may fall within the jurisdictional reach of the Clean Water Act is expansive and may include land features not commonly understood to be a stream or wetlands. The Clean Water Act and its regulations prohibit the unpermitted discharge of pollutants into such waters, including those from a spill or leak. Similarly, Section 404 also prohibits discharges of fill material and certain other activities in waters unless authorized by the issued permit. In June 2015, EPA issued a new rule defining the scope of “Waters of the United States” (WOTUS) that are subject to regulation. The 2015 WOTUS rule was challenged by a number of states and private parties in federal district and circuit courts. In December 2017, EPA and the Corps proposed a rule to repeal the 2015 WOTUS rule and implement the pre-2015 definition. The repeal of the 2015 WOTUS rule took effect in December 2019. In December 2018, EPA and the Corps issued a proposed rule again revising the definition of “Waters of the United States.” The new rule (the Navigable Waters Protection Rule) took effect in June 2020. In most of the pending legal challenges to the 2015 WOTUS rule, the petitioners filed amended complaints to include allegations challenging the 2020 rule. In addition, various industry groups, environmental groups,January 2023, the EPA and states filed new legal challengesthe Army Corps of Engineers published a final revised definition of WOTUS founded upon a pre-2015 definition and including updates to incorporate existing Supreme Court decisions. Judicial developments further add to this uncertainty. In October 2022, the Supreme Court heard oral arguments in Sackett v. EPA regarding the scope and authority of the Clean Water Act and the definition of WOTUS and in May 2023, issued a ruling invalidating certain parts of the January 2023 rule. A revised WOTUS rule was issued in September 2023. Due to the 2020 rule.injunction in certain states, however, the implementation of the September 2023 rule currently varies by state.
States issue a certificate pursuant to Clean Water Act Section 401 that is required for the Corps of Engineers to issue a Section 404 permit. In AugustOctober 2021, the U.S. District Court for the Northern District of ArizonaCalifornia vacated a 2020 rule revising the Section 401 certification process. The Supreme Court stayed this vacatur and, remandedin September 2023, the 2020 rule. In lightEPA finalized its Clean Water Act Section 401 Water Quality Certification Improvement Rule, effective as of this order, agencies have reverted to interpreting WOTUS in line withNovember 27, 2023. While the pre-2015 regulatory regime. In late November 2021, EPA proposed a rule to revise the definition yet again,full extent and impact of these actions is unclear at this time, any disruption in the ability to restore the pre-2015 definition, with updates to reflect recent Supreme Court decisions.
In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators and landowners. Since 2012, several citizen group lawsuits have been filed against mine operators for allegedly violating conditions in their National Pollutant Discharge Elimination System (“NPDES”) permits requiring compliance with West Virginia’s water quality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereas others alleged that discharges of conductivity and sulfate were causing violations of West Virginia’s narrative water quality standards, which generally prohibit adverse effects to aquatic life. The citizen suit groups have sought penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate. The federal district court for the Southern District of West Virginia has ruled in favor of the citizen suit groups in multiple suits alleging violations of the water quality standard for selenium and in two suits alleging violations of water quality standards due to discharges of conductivity (one of which was upheld on appeal by the United States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in large treatment expenses for our lessees. In 2015, the West Virginia Legislature enacted certain changes to West Virginia’s NPDES program to expressly prohibit the direct enforcement of water quality standards against permit holders. EPA approved those changes as a program revision effective in March 2019. This approval may prevent future citizen suits alleging violations of water quality standards.
Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.
Endangered Species Act
The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (“USFWS”) works closely with state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related and oil and gas exploration and production activities. In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while establishing a process to regulate or permit exceptions to such a prohibition. In February 2023, the USFWS published a proposed rule that revised the requirements for an incidental take permit application. A final rule is scheduled for release in 2024. Additionally, in June 2022, the USFWS and the National Marine Fisheries Service published a final rule rescinding the 2020 regulatory definition of “habitat.” If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered or to redesignate a species from threatened to endangered, we or the operators of the properties in which we hold oil and gas or mineral interests could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.
Mine Health and Safety Laws
The operations of our coal lessees and Sisecam Wyoming are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.
Mining accidents in recent years have received national attention and instigated responses at the state and national level that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. Since 2006, heightened scrutiny has been applied to the safe operations of both underground and surface mines. This increased level of review has resulted in an increase in the civil penalties that mine operators have been assessed for non-compliance. Operating companies and their supervisory employees have also been subject to criminal convictions. The Mine Safety and Health Administration ("MSHA") has also advised mine operators that it will be more aggressive in placing mines in the Pattern of Violations program, if a mine’s rate of injuries or significant and substantial citations exceed a certain threshold. A mine that is placed in a Pattern of Violations program will receive additional scrutiny from MSHA.
Surface Mining Control and Reclamation Act of 1977
The Surface Mining Control and Reclamation Act of 1977 ("SMCRA") and similar statutes enacted and enforced by the states impose on mine operators the responsibility of reclaiming the land and compensating the landowner for types of damages occurring as a result of mining operations. To ensure compliance with any reclamation obligations, mine operators are required to post performance bonds. Our coal lessees are contractually obligated under the terms of our leases to comply with all federal, state and local laws, including SMCRA. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the reclamation plan approved by the state regulatory authority. In addition, higher and better uses of the reclaimed property are encouraged.
Mining Permits and Approvals
Numerous governmental permits or approvals such as those required by SMCRA and the Clean Water Act are required for mining operations. In connection with obtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for reclaiming the mined property upon the completion of mining operations. Our lessees have obtained or applied for permits to mine a majority of the coal that is currently planned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional coal planned to be mined over the following five years. However, given the imposition of new requirements in the permits in the form of policies and the increased oversight review that has been exercised by EPA, there are no assurances that they will not experience difficulty and delays in obtaining mining permits in the future. In addition, EPA has used its authority to create significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coal operators.
Employees and Labor Relations
As of December 31, 2021,2023, affiliates of our general partner employed
Human Capital
We believe all individuals are entitled to courtesy, dignity, and respect, and we support a culture of integrity and personal and professional growth. We are strong leaders within our community, and we seek to uphold a positive presence in all areas where we live and work.
Website Access to Partnership Reports
Our Internetinternet address is www.nrplp.com. We make available free of charge on or through our Internet website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not a part of this report. In addition, the SEC maintains an Internet sitea website at www.sec.gov that contains reports, proxy and information statements and other information filed by us.
Corporate Governance Matters
Our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy and our Corporate Governance Guidelines adopted by ourthe Board of Directors, as well as the charter for our Audit Committee are available on our website at www.nrplp.com. Copies of our annual report, our Code of Business Conduct and Ethics, our Disclosure Controls and Procedures Policy, our Corporate Governance Guidelines and our committee charters will be made available upon written request to our principal executive office at 12011415 Louisiana St., Suite 3400,3325, Houston, Texas 77002.
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 boardBoard of directorsDirectors may determine are appropriate. We have significant debt service obligations and obligations to pay cash distributions on our preferred units. To the extent our boardBoard of directorsDirectors 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 exceeds 3.75x.
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, 2021,2023, we and our subsidiaries had approximately $438.5$155.5 million of total indebtedness. The terms and conditions governing the indenture for NRP’s 2025 Senior Notes and Opco’sOpco��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$31 million due thereunder during 2022.2024. 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.
Global pandemics, including the U.K. Financial Conduct Authority announced that it intendsCOVID-19 pandemic have in the past and may continue to stop persuading or compelling banks to submit LIBOR rates after late 2021. Opco’s revolving credit facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which provide that we will adopt a replacement rate that is broadly accepted by the syndicated loan market. We currently do not expect the transition from LIBOR to have a material impact on us. However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty establishing a replacement rate under Opco’s revolving credit facility. In the event that we do not determine a replacement rate for LIBOR, in certain circumstances, Eurodollar Loans under Opco’s revolving credit facility may be suspended and converted to ABR Loans, which could bear higher interest rates. If we are unable to negotiate replacement rates on favorable terms, it could adversely affect our business, financial condition and results of operations. For a description of the interest rate on borrowings under Opco’s revolving credit facility, see “Item 8. Financial Statements and Supplementary Data—Note 11. Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net., Net.”
The COVID-19 pandemic adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities and global trading markets. Coal markets faced substantial challenges prior to the pandemic, and widespread increases in unemployment and decreases in electricity and steel demand further reduced demand and prices for coal in 2020. In addition, demand for and prices of soda ash decreased in 2020, as global manufacturing slowed. Our boardBoard of directorsDirectors 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.
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 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,Prices for soda ash are volatile. Any substantial or extended decline in soda ash prices could have an adverse effect on Sisecam Wyoming’sWyoming’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 ChemicalChemicals 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 all of Foresight’s mining operations, which accounted for approximately 17% of our total revenues in 2021. We also own significant interests in several of Alpha's mining operations, which accounted for approximately 23% of our total revenues in 2021.2023. We also own significant interests in all of Foresight’s mining operations, which accounted for approximately 16% of our total revenues in 2023. Certain other lessees have made acquisitions over the past few years resulting in their having an increased interest 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)("CSAPR") as revised in 2021, regulating emissions of nitrogen oxide and sulfur dioxide, and the Mercury and Air Toxics Rule (MATS)("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 "
Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are also resulting in unfavorable lending and investment policies by institutions and insurance companies which could significantly affect our ability to raise capital or maintain current insurance levels.
Global climate issues continue to attract public and scientific attention. Numerous reports have engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In addition to government regulation of greenhouse gas and other air pollutant emissions, there have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels, such as coal. One example is the Net Zero Banking Alliance, a group of over 100 banks worldwide representing over 40% of global banking assets who are committed to aligning their investment portfolios with net zero emissions by 2050. Further, in October 2023, the Federal Reserve, Office of the Comptroller of the Currency and the Federal Deposit Insurance Corp. released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change. 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.
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. For more information on regulation of greenhouse gas and other air pollutant emissions, see "Items 1. and 2. Business and Properties—Regulation and Environmental Matters.”
If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.
We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:
• | the payment of minimum royalties; |
• | marketing of the minerals mined; |
• | mine plans, including the amount to be mined and the method and timing of mining activities; |
• | processing and blending minerals; |
• | expansion plans and capital expenditures; |
• | credit risk of their customers; |
• | permitting; |
• | insurance and surety bonding; |
• | acquisition of surface rights and other mineral estates; |
• | employee wages; |
• | transportation arrangements; |
• | compliance with applicable laws, including environmental laws; and |
• | mine closure and reclamation. |
A failure on the part of one of our lessees to make royalty payments, including minimum royalty payments, could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the
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 are not made.
In 2024, Sisecam Wyoming’s deca stockpiles will be substantially depleted. Without adding additional capacity,depleted and Sisecam Wyoming's production rates will decline, approximately 200,000 short tons, which would further impact Sisecam Wyoming's profitability. While Sisecam Wyoming is currently evaluating an expansion projectwhether and when to pursue one or more initiatives that wouldcould 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, or 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, 2021,2023, Sisecam Wyoming shipped
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 managing general partner manages and operates NRP. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directorsBoard of the general partnerDirectors 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’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’sunitholder’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.Blackstone. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
• | an existing unitholder’s proportionate ownership interest in NRP will decrease; |
• | the amount of cash available for distribution on each unit may decrease; and |
• | the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline. |
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which 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 morecertain 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 ourmanaging 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 interpretationinterpretations 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.
Ifthe 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 adjustmentsdirectly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible, 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 adjustmentadjustments 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. How
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. Unitholdersunitholders 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.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations and other guidance from the IRS provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023. Thereafter, the obligation to withhold onFor a transfer of interests in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of our common units and for other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.
We have adopted certain valuation methodologies in determining a unitholder’sunitholder’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
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, hesuch 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 consequencesconsequence 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 and operational 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.
In addition, the frequency and magnitude of cyber-attacks is increasing and attackers have become more sophisticated. Cyber-attacks are similarly evolving and include without limitation use of malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. We domay be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognized until deployed. We may also be unable to investigate or remediate incidents as attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.
While we presently maintain insurance coverage to protect against cybersecurity risks. If we procure such coverage in the future,risks, we cannot ensure that it will be sufficient to cover any particular losses we may experience as a result of such cyber-attacks. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent cyber-attacks or other incidents from occurring. If a cyber-attack was to occur, it could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations, misdirected wire transfers, an inability to settle transactions or maintain operations, disruptions in operations, or other adverse events. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability, including regulatory enforcement, violation of privacy or securities laws and regulations, and individual or class action claims. Any cyber incident could have a material adverse effect on our business, financial condition and results of operations.
None.
Cybersecurity Risk Management and Strategy
We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information.
Our overall risk management program includes a cybersecurity risk assessment process, that routinely evaluates potential impacts of cybersecurity risks on our business, including our operations, financial stability, and reputation. These assessments inform our cybersecurity risk mitigation strategies. The results are regularly shared with management and the Audit Committee as part of their involvement in managing and overseeing cybersecurity risks.
Key aspects of our cybersecurity risk management program include:
• | risk assessments designed to help identify material cybersecurity risks to our critical systems and information; |
• | a security team principally responsible for managing (1) our cybersecurity risk assessment processes, (2) our security controls, and (3) our response to cybersecurity incidents; |
• | the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security controls; |
• | cybersecurity awareness training for our employees, incident response personnel, and management; and |
• | a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents. |
We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected us, including our operations, business strategy, results of operations, or financial condition. We face ongoing risks from certain cybersecurity threats that, if realized, are reasonably likely to materially affect us, including our operations, business strategy, results of operations, or financial condition. See "Item 1A. Risk Factors – Our business is subject to cybersecurity risks" included elsewhere in this Annual Report on Form 10-K.
Cybersecurity Governance
Our Board of Directors considers cybersecurity risk as part of its risk oversight function and has delegated to its Audit Committee oversight of cybersecurity and other information technology risks. Our Audit Committee oversees management’s implementation of our cybersecurity risk management program.
Our Audit Committee receives periodic reports from management on our cybersecurity risks. In addition, management updates our Audit Committee, as necessary, regarding significant cybersecurity incidents. Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity. Our Board of Directors also receives briefings from management on our cybersecurity risk management program. Board members receive presentations on cybersecurity topics from IT leadership, which includes our Chief Sustainability and Administrative Officer ("CSAO"), or external experts as part of the Board’s continuing education on topics that impact public companies.
Our cybersecurity team, led by the CSAO, is responsible for coordinating and executing on the cybersecurity response procedures and for seeking assistance from other Partnership stakeholders and external advisors. Our cybersecurity team includes the CSAO and IT leadership. The team has primary responsibility for our overall cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our cybersecurity team includes professionals with deep cybersecurity expertise across multiple industries.
Our management team stays informed about and monitor efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, which may include briefings from internal information technology personnel, threat intelligence and other information obtained from public or private sources, including external consultants engaged by us, and alerts and reports produced by security tools deployed in the IT environment.
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.
None.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NRP Common Units
Our common units are listed and traded on the NYSE under the symbol "NRP." As
ofIntroduction
The following discussion and analysis presentspresent 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 consistsconsist 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
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) from continuing operations less equity earnings from unconsolidated investment, net income attributable to non-controlling interest and gain on reserve swap; plus total distributions from unconsolidated investment, interest expense, net, debt modification expense, loss on extinguishment of debt, depreciation, depletion and amortization and asset impairments. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies. In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnership agreement or Consolidated EBITDDA as defined in Opco's debt agreements. See "
Distributable Cash Flow
Distributable cash flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings, proceeds from asset sales and disposals, including sales of discontinued operations, and return of long-term contract receivables, less maintenance capital expenditures. DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies. In addition, DCF presented below is not calculated or presented on the same basis as distributable cash flow as defined in our partnership agreement, which is used as a metric to determine whether we are able to increase quarterly distributions to our common unitholders. DCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess our ability to make cash distributions and repay debt.
Free Cash Flow
Free cash flow ("FCF") represents net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables, less maintenance and expansion capital expenditures and cash flow used in acquisition costs classified as investing or financing activities. FCF is calculated before mandatory debt repayments. FCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. FCF may not be calculated the same for us as for other companies. FCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess our ability to make cash distributions and repay debt.
Leverage Ratio
Leverage ratio represents the outstanding principal of NRP's debt at the end of the period divided by the last twelve months' Adjusted EBITDA as defined above. NRP believes that leverage ratio is a useful measure to management and investors to evaluate and monitor the indebtedness of NRP relative to its ability to generate income to service such debt and in understanding trends in NRP’s overall financial condition. Leverage ratio may not be calculated the same for us as for other companies and is not a substitute for, and should not be used in conjunction with, GAAP financial ratios.
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"), formerly known as Ciner 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 (formerly named Coal Royalty and Other segment)
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, 20212023 are as follows:
| Operating Segments | ||||||||||||||||||||||||||
| (In thousands) | Mineral Rights | Soda Ash | Corporate and Financing | Total | ||||||||||||||||||||||
| Revenues and other income | $ | 194,493 | $ | 21,871 | $ | — | $ | 216,364 | ||||||||||||||||||
| Net income (loss) from continuing operations | $ | 143,412 | $ | 21,702 | $ | (56,212) | $ | 108,902 | ||||||||||||||||||
| Asset impairments | 5,102 | — | — | 5,102 | ||||||||||||||||||||||
| Net income (loss) from continuing operations excluding asset impairments | $ | 148,514 | $ | 21,702 | $ | (56,212) | $ | 114,004 | ||||||||||||||||||
Adjusted EBITDA (1) | $ | 167,613 | $ | 11,101 | $ | (17,360) | $ | 161,354 | ||||||||||||||||||
| Cash flow provided by (used in) continuing operations | ||||||||||||||||||||||||||
| Operating activities | $ | 159,845 | $ | 11,106 | $ | (49,147) | $ | 121,804 | ||||||||||||||||||
| Investing activities | $ | 2,412 | $ | — | $ | — | $ | 2,412 | ||||||||||||||||||
| Financing activities | $ | (1,132) | $ | — | $ | (87,354) | $ | (88,486) | ||||||||||||||||||
Distributable cash flow (1) | $ | 162,257 | $ | 11,106 | $ | (49,147) | $ | 124,216 | ||||||||||||||||||
Free cash flow (1) | $ | 161,008 | $ | 11,106 | $ | (49,147) | $ | 122,967 | ||||||||||||||||||
Cash flow cushion (1) | N/A | N/A | N/A | $ | 36,172 | |||||||||||||||||||||
| Operating Segments | Corporate and | |||||||||||||||
(In thousands) | Mineral Rights | Soda Ash | Financing | Total | ||||||||||||
Revenues and other income | $ | 296,612 | $ | 73,397 | $ | — | $ | 370,009 | ||||||||
Net income (loss) | $ | 245,527 | $ | 73,140 | $ | (40,232 | ) | $ | 278,435 | |||||||
Asset impairments | 556 | — | — | 556 | ||||||||||||
Net income (loss) excluding asset impairments | $ | 246,083 | $ | 73,140 | $ | (40,232 | ) | $ | 278,991 | |||||||
Adjusted EBITDA (1) | $ | 264,554 | $ | 81,221 | $ | (26,111 | ) | $ | 319,664 | |||||||
Cash flow provided by (used in) continuing operations | ||||||||||||||||
Operating activities | $ | 259,983 | $ | 81,207 | $ | (30,212 | ) | $ | 310,978 | |||||||
Investing activities | $ | 5,426 | $ | — | $ | (10 | ) | $ | 5,416 | |||||||
Financing activities | $ | (583 | ) | $ | — | $ | (342,913 | ) | $ | (343,496 | ) | |||||
Distributable cash flow (1) | $ | 265,409 | $ | 81,207 | $ | (30,222 | ) | $ | 316,394 | |||||||
Free cash flow (1) | $ | 262,446 | $ | 81,207 | $ | (30,222 | ) | $ | 313,431 | |||||||
(1) | See"—Results of Operations" below for reconciliations to the most comparable GAAP financial measures. | |||||||||||||
Business Outlook and Quarterly Distributions
We generated $121.8$311.0 million of netoperating cash provided by operating activitiesflow and $123.0$313.4 million of free cash flow during the year ended December 31, 20212023, and ended the year with $235.5with $71.2 million of liquidityliquidity consisting of $135.5$12.0 million of cash and cash equivalents and $100and $59.2 million of borrowing capacity under our Opco Credit Facility.
In 2023, we received notices from paying more than one-halfholders of the quarterly distribution onClass A Convertible Preferred Units representing limited partner interests in NRP (the "preferred units") exercising their right to either convert or redeem, at our election, an aggregate of 83,333 preferred units. We chose to redeem the preferred units for $83.3 million in cash ifrather than converting them into common units. In 2023, we also executed negotiated transactions with holders of the preferred units pursuant to which we repurchased and retired an aggregate of 95,001 preferred units for $95.0 million in cash. Of the originally issued 250,000 preferred units, 71,666 preferred units remain outstanding as of December 31, 2023. Following these redemptions and repurchases, the subject units were retired and no longer remain outstanding and Blackstone ceased to own any preferred units. All rights of Blackstone related to its ownership of preferred units ceased, including Blackstone's right to appoint a board designee.
In 2023, we negotiated transactions with holders of the warrants to purchase common units (the "warrants") pursuant to which we repurchased and retired an aggregate of 752,500 warrants with a strike price of $22.81 and 710,000 warrants with a strike price of $34.00 for approximately $56.1 million in cash.
In January and February 2024, holders of our consolidated leverage ratio exceeds 3.75x. Accordingly,warrants exercised a total of 1,219,665 warrants with a strike price of $34.00. We settled the warrants on a net basis with a total of $56 million in cash and 198,767 common units. Following these transactions, of the originally issued 4,000,000 warrants, 320,335 warrants with a strike price of $34.00 remain outstanding.
In February 2024, we exercised our option under the Opco Credit Facility to increase the total aggregate commitment under the Opco Credit Facility twice, initially by $30 million from $155.0 million to $185.0 million and subsequently by $15.0 million from $185.0 million to $200.0 million. These increases in the total aggregate commitment were made pursuant to an accordion feature of the Opco Credit Facility. In connection with the initial increase, a new lender joined the lending group with a commitment of $30.0 million. The Opco Credit Facility otherwise continues to operate under its existing terms and conditions in all material respects.
In February 2024, the Board of Directors of our general partner had declared a cash distribution on our preferred unitsof $0.75 per common unit of NRP with respect to be paid one-half in kind through the issuance of additional preferred units (“PIK units”) in 2021 when our leverage ratio exceeded 3.75x. Our consolidated leverage ratio fell below 3.75x during the fourth quarter of 2021 to 2.7x at December 31, 2021, allowing us to fully redeem at par all 19,321 paid-in-kind2023 as well as a $2.15 million cash distribution on the preferred units
Mineral Rights Business Segment
Revenues and other income in 2021 were higher by $64.9during the year ended December 31, 2023 decreased $32.6 million, or 10%, as compared to the prior year. This increase isyear primarily a result of strongerdue to decreased metallurgical coal sales prices, decreased revenues from oil and gas royalties, lower transportation and processing services revenues and certain carbon neutral initiative transactions entered into in 2022. Cash provided by operating activities and free cash flow decreased $2.8 million and $2.1 million, respectively, compared to the prior year period primarily due to the lower revenues during the year ended December 31, 2023 as compared to the prior year period.
Metallurgical and thermal coal prices saw significant variability in 2023, and were off the record highs seen in 2022, but finished the year strong relative to historical norms. We believe limitations from ongoing labor shortages, access to capital, and inflationary pressures should provide continued price support for metallurgical and thermal coal in 2024, despite headwinds from lower steel demand and pricingthe long-term secular decline in 2021.
We continue to explore and identify alternativecarbon neutral revenue sources across our large portfolio of land,surface, mineral, and timber assets. The types of opportunities includeassets, including the permanent sequestration of carbon dioxide underground and in standing forests, and the generation of electricity using geothermal, solar and wind energy. We executed our first carbon neutral project in the fourth quarter of 2021 through the sale of 1.1 million carbon offset cred
Soda Ash Business Segment
Revenues and other income in 2021during the year ended December 31, 2023 were higher by $11.1$13.6 million, or 23%, as compared to the prior year primarily due to higher sales prices driven by strong demand domestically, partially offset by lower soda ash production and sales volumes.
Cash provided by operating activities and free cash flow during the year ended December 31, 2023 increased $36.5 million as compared to the prior year period as demand and pricing for soda ash continuesdue to improve globally from the lows caused by the COVID-19 pandemic.
Strong sales prices at Sisecam Wyoming for the year ended December 31, 2023 more than offset input cost inflation, supply chain difficulties, and the influx of supply from China in 2020. In addition, strong fourth quarter 2021the latter part of the year. However, we believe this increase in global soda ash demandproduction will result in an oversupplied market and pricing resulteda decline in further improved operating results and we received a $13.2 million quarterly distribution with respect to these strong fourth quarter 2021 operating resultssoda ash prices in February 2022.2024.
Year Ended December 31, 20212023 and 20202022 Compared
Revenues and Other Income
The following table includes our revenues and other income by operating segment:
| For the Year Ended December 31, | Increase | Percentage | ||||||||||||||
Operating Segment (In thousands) | 2023 | 2022 | (Decrease) | Change | ||||||||||||
Mineral Rights | $ | 296,612 | $ | 329,167 | $ | (32,555 | ) | (10 | )% | |||||||
Soda Ash | 73,397 | 59,795 | 13,602 | 23 | % | |||||||||||
Total | $ | 370,009 | $ | 388,962 | $ | (18,953 | ) | (5 | )% | |||||||
| For the Year Ended December 31, | ||||||||||||||||||||||||||
| Operating Segment (In thousands) | 2021 | 2020 | Increase | Percentage Change | ||||||||||||||||||||||
| Mineral Rights | $ | 194,493 | $ | 129,592 | $ | 64,901 | 50 | % | ||||||||||||||||||
| Soda Ash | 21,871 | 10,728 | 11,143 | 104 | % | |||||||||||||||||||||
| Total | $ | 216,364 | $ | 140,320 | $ | 76,044 | 54 | % | ||||||||||||||||||
The changes in revenues and other income isare discussed for each of the operating segments below:
Mineral Rights
The following table presents coal sales volumes, coal royalty revenue per ton and coal royalty revenues by major coal producing region, the significant categories of other revenues and other income:
| For the Year Ended December 31, | Increase (Decrease) | Percentage Change | |||||||||||||||||||||
| (In thousands, except per ton data) | 2021 | 2020 | |||||||||||||||||||||
| Coal sales volumes (tons) | |||||||||||||||||||||||
| Appalachia | |||||||||||||||||||||||
| Northern | 1,335 | 647 | 688 | 106 | % | ||||||||||||||||||
| Central | 12,279 | 10,111 | 2,168 | 21 | % | ||||||||||||||||||
| Southern | 1,571 | 889 | 682 | 77 | % | ||||||||||||||||||
| Total Appalachia | 15,185 | 11,647 | 3,538 | 30 | % | ||||||||||||||||||
| Illinois Basin | 9,388 | 3,381 | 6,007 | 178 | % | ||||||||||||||||||
| Northern Powder River Basin | 3,151 | 1,738 | 1,413 | 81 | % | ||||||||||||||||||
| Gulf Coast | 55 | — | 55 | 100 | % | ||||||||||||||||||
| Total coal sales volumes | 27,779 | 16,766 | 11,013 | 66 | % | ||||||||||||||||||
| Coal royalty revenue per ton | |||||||||||||||||||||||
| Appalachia | |||||||||||||||||||||||
| Northern | $ | 6.51 | $ | 2.36 | $ | 4.15 | 176 | % | |||||||||||||||
| Central | 5.71 | 4.17 | 1.54 | 37 | % | ||||||||||||||||||
| Southern | 9.14 | 4.75 | 4.39 | 92 | % | ||||||||||||||||||
| Illinois Basin | 2.12 | 2.36 | (0.24) | (10) | % | ||||||||||||||||||
| Northern Powder River Basin | 3.54 | 3.50 | 0.04 | 1 | % | ||||||||||||||||||
| Gulf Coast | 0.60 | — | 0.60 | 100 | % | ||||||||||||||||||
| Combined average coal royalty revenue per ton | 4.47 | 3.70 | 0.77 | 21 | % | ||||||||||||||||||
| Coal royalty revenues | |||||||||||||||||||||||
| Appalachia | |||||||||||||||||||||||
| Northern | $ | 8,691 | $ | 1,526 | $ | 7,165 | 470 | % | |||||||||||||||
| Central | 70,149 | 42,207 | 27,942 | 66 | % | ||||||||||||||||||
| Southern | 14,355 | 4,221 | 10,134 | 240 | % | ||||||||||||||||||
| Total Appalachia | 93,195 | 47,954 | 45,241 | 94 | % | ||||||||||||||||||
| Illinois Basin | 19,917 | 7,973 | 11,944 | 150 | % | ||||||||||||||||||
| Northern Powder River Basin | 11,151 | 6,086 | 5,065 | 83 | % | ||||||||||||||||||
| Gulf Coast | 33 | — | 33 | 100 | % | ||||||||||||||||||
| Unadjusted coal royalty revenues | 124,296 | 62,013 | 62,283 | 100 | % | ||||||||||||||||||
| Coal royalty adjustment for minimum leases | (20,207) | (10,145) | (10,062) | (99) | % | ||||||||||||||||||
| Total coal royalty revenues | $ | 104,089 | $ | 51,868 | $ | 52,221 | 101 | % | |||||||||||||||
| Other revenues | |||||||||||||||||||||||
| Production lease minimum revenues | $ | 14,269 | $ | 21,749 | $ | (7,480) | (34) | % | |||||||||||||||
| Minimum lease straight-line revenues | 20,564 | 16,796 | 3,768 | 22 | % | ||||||||||||||||||
Forest CO2 sequestration revenues | 13,790 | — | 13,790 | 100 | % | ||||||||||||||||||
| Wheelage revenues | 10,065 | 7,025 | 3,040 | 43 | % | ||||||||||||||||||
| Property tax revenues | 6,028 | 5,786 | 242 | 4 | % | ||||||||||||||||||
| Coal overriding royalty revenues | 4,367 | 4,977 | (610) | (12) | % | ||||||||||||||||||
| Lease amendment revenues | 4,696 | 3,450 | 1,246 | 36 | % | ||||||||||||||||||
| Aggregates royalty revenues | 1,889 | 1,717 | 172 | 10 | % | ||||||||||||||||||
| Oil and gas royalty revenues | 4,506 | 5,816 | (1,310) | (23) | % | ||||||||||||||||||
| Other revenues | 933 | 982 | (49) | (5) | % | ||||||||||||||||||
| Total other revenues | $ | 81,107 | $ | 68,298 | $ | 12,809 | 19 | % | |||||||||||||||
| Royalty and other mineral rights | $ | 185,196 | $ | 120,166 | $ | 65,030 | 54 | % | |||||||||||||||
| Transportation and processing services revenues | 9,052 | 8,845 | 207 | 2 | % | ||||||||||||||||||
| Gain on asset sales and disposals | 245 | 581 | (336) | (58) | % | ||||||||||||||||||
| Total Mineral Rights segment revenues and other income | $ | 194,493 | $ | 129,592 | $ | 64,901 | 50 | % | |||||||||||||||
For the Year Ended December 31, | Increase | Percentage | ||||||||||||||
(In thousands, except per ton data) | 2023 | 2022 | (Decrease) | Change | ||||||||||||
Coal sales volumes (tons) | ||||||||||||||||
Appalachia | ||||||||||||||||
Northern | 1,145 | 1,696 | (551 | ) | (32 | )% | ||||||||||
Central | 13,927 | 13,646 | 281 | 2 | % | |||||||||||
Southern | 2,670 | 1,784 | 886 | 50 | % | |||||||||||
Total Appalachia | 17,742 | 17,126 | 616 | 4 | % | |||||||||||
Illinois Basin | 8,119 | 11,135 | (3,016 | ) | (27 | )% | ||||||||||
Northern Powder River Basin | 4,589 | 4,288 | 301 | 7 | % | |||||||||||
Gulf Coast | 1,477 | 385 | 1,092 | 284 | % | |||||||||||
Total coal sales volumes | 31,927 | 32,934 | (1,007 | ) | (3 | )% | ||||||||||
Coal royalty revenue per ton | ||||||||||||||||
Appalachia | ||||||||||||||||
Northern | $ | 7.15 | $ | 8.75 | $ | (1.60 | ) | (18 | )% | |||||||
Central | 8.95 | 10.47 | (1.52 | ) | (15 | )% | ||||||||||
Southern | 12.81 | 13.50 | (0.69 | ) | (5 | )% | ||||||||||
Illinois Basin | 3.61 | 2.50 | 1.11 | 44 | % | |||||||||||
Northern Powder River Basin | 4.50 | 4.07 | 0.43 | 11 | % | |||||||||||
Gulf Coast | 0.66 | 0.58 | 0.08 | 14 | % | |||||||||||
Combined average coal royalty revenue per ton | 6.83 | 6.90 | (0.07 | ) | (1 | )% | ||||||||||
Coal royalty revenues | ||||||||||||||||
Appalachia | ||||||||||||||||
Northern | $ | 8,192 | $ | 14,836 | $ | (6,644 | ) | (45 | )% | |||||||
Central | 124,631 | 142,930 | (18,299 | ) | (13 | )% | ||||||||||
Southern | 34,205 | 24,076 | 10,129 | 42 | % | |||||||||||
Total Appalachia | 167,028 | 181,842 | (14,814 | ) | (8 | )% | ||||||||||
Illinois Basin | 29,350 | 27,856 | 1,494 | 5 | % | |||||||||||
Northern Powder River Basin | 20,666 | 17,437 | 3,229 | 19 | % | |||||||||||
Gulf Coast | 969 | 223 | 746 | 335 | % | |||||||||||
Unadjusted coal royalty revenues | 218,013 | 227,358 | (9,345 | ) | (4 | )% | ||||||||||
Coal royalty adjustment for minimum leases | (2 | ) | (402 | ) | 400 | 100 | % | |||||||||
Total coal royalty revenues | $ | 218,011 | $ | 226,956 | $ | (8,945 | ) | (4 | )% | |||||||
Other revenues | ||||||||||||||||
Production lease minimum revenues | $ | 3,322 | $ | 5,854 | $ | (2,532 | ) | (43 | )% | |||||||
Minimum lease straight-line revenues | 19,389 | 18,792 | 597 | 3 | % | |||||||||||
Carbon neutral initiative revenues | 2,969 | 8,600 | (5,631 | ) | (65 | )% | ||||||||||
Wheelage revenues | 12,191 | 13,961 | (1,770 | ) | (13 | )% | ||||||||||
Property tax revenues | 6,219 | 5,878 | 341 | 6 | % | |||||||||||
Coal overriding royalty revenues | 2,175 | 3,434 | (1,259 | ) | (37 | )% | ||||||||||
Lease amendment revenues | 3,070 | 3,201 | (131 | ) | (4 | )% | ||||||||||
Aggregates royalty revenues | 2,876 | 3,299 | (423 | ) | (13 | )% | ||||||||||
Oil and gas royalty revenues | 7,387 | 16,161 | (8,774 | ) | (54 | )% | ||||||||||
Other revenues | 1,124 | 877 | 247 | 28 | % | |||||||||||
Total other revenues | $ | 60,722 | $ | 80,057 | $ | (19,335 | ) | (24 | )% | |||||||
Royalty and other mineral rights | $ | 278,733 | $ | 307,013 | $ | (28,280 | ) | (9 | )% | |||||||
Transportation and processing services revenues | 14,923 | 21,072 | (6,149 | ) | (29 | )% | ||||||||||
Gain on asset sales and disposals | 2,956 | 1,082 | 1,874 | 173 | % | |||||||||||
Total Mineral Rights segment revenues and other income | $ | 296,612 | $ | 329,167 | $ | (32,555 | ) | (10 | )% | |||||||
Approximately 65%70% of coal royalty revenues and approximately 50% of coal royalty sales volumes were derived from metallurgical coal during the year ended December 31, 2021.2023. Total coal royalty revenues increased $52.2decreased $8.9 million from 20202022 to 2021 primarily as a result of stronger metallurgical coal demand and pricing in 2021.2023. The discussion of these increases by region is as follows:
• | Appalachia: Coal royalty revenues decreased $14.8 million primarily due to decreased metallurgical coal sales prices during the year ended December 31, 2023, as compared to the prior year. |
• | Illinois Basin: Coal royalty revenues increased $1.5 million primarily due to higher thermal coal sales prices, partially offset by lower coal sales volumes as compared to the prior year. |
• | Northern Powder River Basin: Coal royalty revenues increased $3.2 million due to increased sales volumes and higher coal sales prices during the year ended December 31, 2023, as compared to the prior year. The increase in sales volumes was due to our lessee mining more on our property during 2023 as compared to 2022 in accordance with its mine plan. |
Other Revenues
Other revenues increased $45.2decreased $19.3 million primarily due to a 30% increase in sales volumes in addition to higher sales pricesduring the year ended December 31, 2023 as compared to the prior year primarily due to the following:
• | An $8.8 million decrease in oil and gas revenues primarily as a result of decreased natural gas prices as compared to the prior year; |
• | A $5.6 million decrease in carbon neutral initiative revenues as compared to the prior year. Carbon neutral initiative revenues recognized in 2023 primarily related to subsurface CO2 storage and forest offset credits. Carbon neutral initiative revenues recognized in 2022 primarily related to subsurface CO2 storage and geothermal energy transactions; and |
| • | A $2.5 million decrease in production lease minimum revenues primarily as a result of a decrease in breakage revenues as compared to the prior year. |
Transportation and Processing Services Revenues
•Illinois Basin: Coal royaltyTransportation and processing services revenues increased $11.9decreased $6.1 million during the year ended December 31, 2023 as compared to the prior year primarily due to a 178% increase in sales volumes. Intemporary relocation of certain production off of NRP's coal reserves. The fee per ton associated with the second quarter of 2020, we entered into lease amendments with Foresight pursuant to which Foresight agreed to pay us fixed cash payments to satisfy all obligations arising outtransportation and processing of the existing variousnon-NRP coal mining leasesis less than the fee per ton associated with the transportation and transportation infrastructure fee agreements between us and Foresight for calendar years 2020 and 2021. As a resultprocessing of these amendments, actual revenues recognized from Foresight were flat period-over-period.
Soda Ash
Revenues and other income related to our Soda Ash segment increased $11.1$13.6 million comparedcompared to the prior year asprimarily due to higher sales prices driven by strong demand and pricing fordomestically, partially offset by lower soda ash continues to improve globally from the lows caused by the COVID-19 pandemic.
Operating and Other Expenses
The following table presents the significant categories of our consolidated operating and other expenses:
| For the Year Ended December 31, | Increase (Decrease) | Percentage Change | ||||||||||||||||||||||||
| (In thousands) | 2021 | 2020 | ||||||||||||||||||||||||
| Operating expenses | ||||||||||||||||||||||||||
| Operating and maintenance expenses | $ | 27,049 | $ | 24,795 | $ | 2,254 | 9 | % | ||||||||||||||||||
| Depreciation, depletion and amortization | 19,075 | 9,198 | 9,877 | 107 | % | |||||||||||||||||||||
| General and administrative expenses | 17,360 | 14,293 | 3,067 | 21 | % | |||||||||||||||||||||
| Asset impairments | 5,102 | 135,885 | (130,783) | (96) | % | |||||||||||||||||||||
| Total operating expenses | $ | 68,586 | $ | 184,171 | $ | (115,585) | (63) | % | ||||||||||||||||||
| For the Year Ended December 31, | Increase | Percentage | ||||||||||||||
(In thousands) | 2023 | 2022 | (Decrease) | Change | ||||||||||||
Operating expenses | ||||||||||||||||
Operating and maintenance expenses | $ | 32,315 | $ | 34,903 | $ | (2,588 | ) | (7 | )% | |||||||
Depreciation, depletion and amortization | 18,489 | 22,519 | (4,030 | ) | (18 | )% | ||||||||||
General and administrative expenses | 26,111 | 21,852 | 4,259 | 19 | % | |||||||||||
Asset impairments | 556 | 4,457 | (3,901 | ) | (88 | )% | ||||||||||
Total operating expenses | $ | 77,471 | $ | 83,731 | $ | (6,260 | ) | (7 | )% | |||||||
Other expenses, net | ||||||||||||||||
Interest expense, net | $ | 14,103 | $ | 26,274 | $ | (12,171 | ) | (46 | )% | |||||||
Loss on extinguishment of debt | — | 10,465 | (10,465 | ) | (100 | )% | ||||||||||
Total other expenses, net | $ | 14,103 | $ | 36,739 | $ | (22,636 | ) | (62 | )% | |||||||
Total operating expenses decreased by $115.6$6.3 million primarily due to a $130.8 million decrease in asset impairments. Asset impairments in 2021 primarily related to a lease termination while asset impairments in 2020the following:
• | A $2.6 million decrease in operating and maintenance expenses primarily as a result of lower overriding royalty expense from an agreement with Western Pocahontas Properties Limited Partnership ("WPPLP") in 2023 as compared to 2022. This overriding royalty expense is fully offset by coal royalty revenue we receive from this property. |
• | A $3.9 million decrease in asset impairments as compared to the prior year. |
• | A $4.0 million decrease in depreciation, depletion and amortization expense primarily driven by lower Illinois Basin coal royalty sales volumes during the year ended December 31, 2023, as compared to the prior year. |
These decreases were due to weakened coal markets that resulted in termination of certain coal leases, changes to lessee mine plans resulting in permanent moves off certain of our coal properties and decreased oil and gas drilling activity which negatively impacted the outlook for NRP's frac sand properties. This decrease was partially offset by a $9.9$4.3 million increase in depreciation, depletiongeneral and amortizationadministrative expenses primarily due to higher long-term incentive expense primarilyduring the year ended December 31, 2023, as compared to the prior year.
Total other expenses, net decreased $22.6 million primarily due to a $12.2 million decrease in interest expense, net as a result of increased production at certain Illinois Basin coal properties. The remaining cost increases primarilyless debt outstanding during 2023 as compared to the prior year, and a $10.5 million decrease related to increased incentive compensation expense as a resultthe loss on early extinguishment of significantly improved Partnership operating results year-over-year and increased overriding royalty expense duedebt related to higher coal sales and royalty revenue in 2021.
The following table reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment:
| Operating Segments | ||||||||||||||||||||||||||
| For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Corporate and Financing | Total | ||||||||||||||||||||||
| December 31, 2021 | ||||||||||||||||||||||||||
| Net income (loss) from continuing operations | $ | 143,412 | $ | 21,702 | $ | (56,212) | $ | 108,902 | ||||||||||||||||||
| Less: equity earnings from unconsolidated investment | — | (21,871) | — | (21,871) | ||||||||||||||||||||||
| Add: total distributions from unconsolidated investment | — | 11,270 | — | 11,270 | ||||||||||||||||||||||
| Add: interest expense, net | 24 | — | 38,852 | 38,876 | ||||||||||||||||||||||
| Add: depreciation, depletion and amortization | 19,075 | — | — | 19,075 | ||||||||||||||||||||||
| Add: asset impairments | 5,102 | — | — | 5,102 | ||||||||||||||||||||||
| Adjusted EBITDA | $ | 167,613 | $ | 11,101 | $ | (17,360) | $ | 161,354 | ||||||||||||||||||
| December 31, 2020 | ||||||||||||||||||||||||||
| Net income (loss) from continuing operations | $ | (40,180) | $ | 10,543 | $ | (55,182) | $ | (84,819) | ||||||||||||||||||
| Less: equity earnings from unconsolidated investment | — | (10,728) | — | (10,728) | ||||||||||||||||||||||
| Add: total distributions from unconsolidated investment | — | 14,210 | — | 14,210 | ||||||||||||||||||||||
| Add: interest expense, net | 79 | — | 40,889 | 40,968 | ||||||||||||||||||||||
| Add: depreciation, depletion and amortization | 9,198 | — | — | 9,198 | ||||||||||||||||||||||
| Add: asset impairments | 135,885 | — | — | 135,885 | ||||||||||||||||||||||
| Adjusted EBITDA | $ | 104,982 | $ | 14,025 | $ | (14,293) | $ | 104,714 | ||||||||||||||||||
| Operating Segments | Corporate and | |||||||||||||||
For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Financing | Total | ||||||||||||
December 31, 2023 | ||||||||||||||||
Net income (loss) | $ | 245,527 | $ | 73,140 | $ | (40,232 | ) | $ | 278,435 | |||||||
Less: equity earnings from unconsolidated investment | — | (73,397 | ) | — | (73,397 | ) | ||||||||||
Add: total distributions from unconsolidated investment | — | 81,478 | — | 81,478 | ||||||||||||
Add: interest expense, net | — | — | 14,103 | 14,103 | ||||||||||||
Add: depreciation, depletion and amortization | 18,471 | — | 18 | 18,489 | ||||||||||||
Add: asset impairments | 556 | — | — | 556 | ||||||||||||
Adjusted EBITDA | $ | 264,554 | $ | 81,221 | $ | (26,111 | ) | $ | 319,664 | |||||||
December 31, 2022 | ||||||||||||||||
Net income (loss) | $ | 267,448 | $ | 59,635 | $ | (58,591 | ) | $ | 268,492 | |||||||
Less: equity earnings from unconsolidated investment | — | (59,795 | ) | — | (59,795 | ) | ||||||||||
Add: total distributions from unconsolidated investment | — | 44,835 | — | 44,835 | ||||||||||||
Add: interest expense, net | — | — | 26,274 | 26,274 | ||||||||||||
Add: loss on extinguishment of debt | — | — | 10,465 | 10,465 | ||||||||||||
Add: depreciation, depletion and amortization | 22,519 | — | — | 22,519 | ||||||||||||
Add: asset impairments | 4,457 | — | — | 4,457 | ||||||||||||
Adjusted EBITDA | $ | 294,424 | $ | 44,675 | $ | (21,852 | ) | $ | 317,247 | |||||||
Net income increased $9.9 million primarily due to the decrease in operating and other expenses, net, partially offset by the decrease in revenues and other income, both discussed above. Adjusted EBITDA increased $56.6$2.4 million primarily due to a $62.6$36.5 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, 2023 as compared to the prior year due to Sisecam Wyoming's strong operating performance in the first half of 2023. This increase was partially offset by a $29.9 million decrease in Adjusted EBITDA within our Mineral Rights segment as a result of higherlower revenues and other income during the year ended December 31, 20212023 as discussed above. This increase was partially offset by a $2.9 million decrease in Adjusted EBITDA within our Soda Ash segment as a result of lower cash distributions received from Sisecam Wyoming during the year ended December 31, 2021 as compared to the prior yearabove and a $3.1$4.3 million decrease in Adjusted EBITDA within our Corporate and Financing segment as a result of increasedthe increase in general and administrative costs primarily due to increased incentive compensationexpenses during the year ended December 31, 2023 as a result of significantly improved Partnership operating results year-over-year.
Distributable Cash Flow ("DCF"), and Free Cash Flow ("FCF")
The following table presents the three major categories of the statement of cash flows by business segment:
| Operating Segments | Corporate and | |||||||||||||||
For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Financing | Total | ||||||||||||
December 31, 2023 | ||||||||||||||||
Cash flow provided by (used in) | ||||||||||||||||
Operating activities | $ | 259,983 | $ | 81,207 | $ | (30,212 | ) | $ | 310,978 | |||||||
Investing activities | 5,426 | — | (10 | ) | 5,416 | |||||||||||
Financing activities | (583 | ) | — | (342,913 | ) | (343,496 | ) | |||||||||
December 31, 2022 | ||||||||||||||||
Cash flow provided by (used in) | ||||||||||||||||
Operating activities | $ | 262,807 | $ | 44,672 | $ | (40,641 | ) | $ | 266,838 | |||||||
Investing activities | 2,806 | — | (118 | ) | 2,688 | |||||||||||
Financing activities | (614 | ) | — | (365,341 | ) | (365,955 | ) | |||||||||
| Operating Segments | ||||||||||||||||||||||||||
| For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Corporate and Financing | Total | ||||||||||||||||||||||
| 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) | ||||||||||||||||||||||
| December 31, 2020 | ||||||||||||||||||||||||||
| Cash flow provided by (used in) continuing operations | ||||||||||||||||||||||||||
| Operating activities | $ | 124,737 | $ | 14,037 | $ | (51,206) | $ | 87,568 | ||||||||||||||||||
| Investing activities | 1,745 | — | — | 1,745 | ||||||||||||||||||||||
| Financing activities | — | — | (87,788) | (87,788) | ||||||||||||||||||||||
The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCF FCF and cash flow cushion:
| Operating Segments | ||||||||||||||||||||||||||
| For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Corporate and Financing | Total | ||||||||||||||||||||||
| December 31, 2021 | ||||||||||||||||||||||||||
| Net cash provided by (used in) operating activities of continuing operations | $ | 159,845 | $ | 11,106 | $ | (49,147) | $ | 121,804 | ||||||||||||||||||
| Add: proceeds from asset sales and disposals | 249 | — | — | 249 | ||||||||||||||||||||||
| Add: return of long-term contract receivable | 2,163 | — | — | 2,163 | ||||||||||||||||||||||
| Distributable cash flow | $ | 162,257 | $ | 11,106 | $ | (49,147) | $ | 124,216 | ||||||||||||||||||
| Less: proceeds from asset sales and disposals | (249) | — | — | (249) | ||||||||||||||||||||||
| Less: acquisition costs | (1,000) | — | — | (1,000) | ||||||||||||||||||||||
| Free cash flow | $ | 161,008 | $ | 11,106 | $ | (49,147) | $ | 122,967 | ||||||||||||||||||
| Less: mandatory Opco debt repayments | (39,396) | |||||||||||||||||||||||||
| Less: preferred unit distributions | (15,571) | |||||||||||||||||||||||||
| Less: common unit distributions | (22,645) | |||||||||||||||||||||||||
| Less: warrant cash settlement | (9,183) | |||||||||||||||||||||||||
| Cash flow cushion | $ | 36,172 | ||||||||||||||||||||||||
| Operating Segments | ||||||||||||||||||||||||||
| For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Corporate and Financing | Total | ||||||||||||||||||||||
| December 31, 2020 | ||||||||||||||||||||||||||
| Net cash provided by (used in) operating activities of continuing operations | $ | 124,737 | $ | 14,037 | $ | (51,206) | $ | 87,568 | ||||||||||||||||||
| Add: proceeds from asset sales and disposals | 623 | — | — | 623 | ||||||||||||||||||||||
| Add: proceeds from sale of discontinued operations | — | — | — | (65) | ||||||||||||||||||||||
| Add: return of long-term contract receivable | 2,122 | — | — | 2,122 | ||||||||||||||||||||||
| Distributable cash flow | $ | 127,482 | $ | 14,037 | $ | (51,206) | $ | 90,248 | ||||||||||||||||||
| Less: proceeds from asset sales and disposals | (623) | — | — | (623) | ||||||||||||||||||||||
| Less: proceeds from sale of discontinued operations | — | — | — | 65 | ||||||||||||||||||||||
| Less: acquisition costs | (1,000) | — | — | (1,000) | ||||||||||||||||||||||
| Free cash flow | $ | 125,859 | $ | 14,037 | $ | (51,206) | $ | 88,690 | ||||||||||||||||||
| Less: mandatory Opco debt repayments | (46,176) | |||||||||||||||||||||||||
| Less: preferred unit distributions | (26,363) | |||||||||||||||||||||||||
| Less: common unit distributions | (16,890) | |||||||||||||||||||||||||
| Cash flow cushion | $ | (739) | ||||||||||||||||||||||||
| Operating Segments | Corporate and | |||||||||||||||
For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Financing | Total | ||||||||||||
December 31, 2023 | ||||||||||||||||
Net cash provided by (used in) operating activities | $ | 259,983 | $ | 81,207 | $ | (30,212 | ) | $ | 310,978 | |||||||
Add: proceeds from asset sales and disposals | 2,963 | — | — | 2,963 | ||||||||||||
Add: return of long-term contract receivable | 2,463 | — | — | 2,463 | ||||||||||||
Less: maintenance capital expenditures | — | — | (10 | ) | (10 | ) | ||||||||||
Distributable cash flow | $ | 265,409 | $ | 81,207 | $ | (30,222 | ) | $ | 316,394 | |||||||
Less: proceeds from asset sales and disposals | (2,963 | ) | — | — | (2,963 | ) | ||||||||||
Free cash flow | $ | 262,446 | $ | 81,207 | $ | (30,222 | ) | $ | 313,431 | |||||||
| Operating Segments | Corporate and | |||||||||||||||
For the Year Ended (In thousands) | Mineral Rights | Soda Ash | Financing | Total | ||||||||||||
December 31, 2022 | ||||||||||||||||
Net cash provided by (used in) operating activities | $ | 262,807 | $ | 44,672 | $ | (40,641 | ) | $ | 266,838 | |||||||
Add: proceeds from asset sales and disposals | 1,083 | — | — | 1,083 | ||||||||||||
Add: return of long-term contract receivable | 1,723 | — | — | 1,723 | ||||||||||||
Less: maintenance capital expenditures | — | — | (118 | ) | (118 | ) | ||||||||||
Distributable cash flow | $ | 265,613 | $ | 44,672 | $ | (40,759 | ) | $ | 269,526 | |||||||
Less: proceeds from asset sales and disposals | (1,083 | ) | — | — | (1,083 | ) | ||||||||||
Free cash flow | $ | 264,530 | $ | 44,672 | $ | (40,759 | ) | $ | 268,443 | |||||||
Cash provided by operating activities, DCF and FCF increased $34.0$44.1 million, $46.9 million and $34.3$45.0 million, respectively primarily duefrom 2022 to the increase in Mineral Rights2023. The discussion by segment DCF and FCF of $34.8 million and $35.1 million, respectively. The increase in Mineral Rights DCF and FCF was primarily driven by stronger metallurgical coal demand and pricing in 2021 and $13.8 million of cash received in the fourth quarter of 2021is as a result of the sale of 1.1 million forest carbon offset credits.
• | Mineral Rights Segment: Cash provided by operating activities, DCF and FCF decreased $2.8 million, $0.2 million and $2.1 million, respectively primarily due to the segment's decrease in revenues and other income as discussed above. |
• | Soda Ash Segment: Cash provided by operating activities, DCF and FCF increased $36.5 million as a result of higher cash distributions received from Sisecam Wyoming in 2023 driven by Sisecam Wyoming's strong operating performance in the first half of 2023. |
• | Corporate and Financing Segment: Cash used in operating activities decreased $10.4 million and DCF and FCF increased $10.5 million primarily due to lower cash paid for interest in 2023 as a result of the retirement of the 2025 Senior Notes in 2022. |
For discussion of our Results of Operations comparing 20202022 to 2019,2021, refer to our 20202022 Annual Report on Form 10-K filed March 15, 20213, 2023 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."Operations."
Current Liquidity
As of December 31, 2021,2023, we had total liquidity of $235.5$71.2 million, consisting of $135.5$12.0 million of cash and cash equivalents and $100$59.2 million in borrowing capacity under our Opco Credit Facility. We have significant debt service obligations, including approximately $40$31 million of principal repayments on Opco’s senior notes in 2022. We believe2024. As of December 31, 2023 our liquidity position provides us with the flexibility to continue paying down debt and manageleverage ratio was 0.5x. The following table calculates our business through the current market environment.
(In thousands) | For the Year Ended December 31, 2023 | |||
Adjusted EBITDA | $ | 319,664 | ||
Debt—at December 31, 2023 | $ | 155,525 | ||
Leverage Ratio | 0.5x | |||
Cash Flows
Year Ended December 31, 20212023 and 20202022 Compared
Cash flows provided by operating activities increased $32.5$44.1 million, from $89.3$266.8 million induring the year ended December 31, 20202022 to $121.8$311.0 million induring the year ended December 31, 2021 primarily related2023 due to increased coal royalty cash flow in 2021 as a result of stronger metallurgical coal demandwithin our Soda Ash and pricing in 2021, the sale of 1.1 million forest carbon offset credits in 2021Corporate and lower cash paid for interest year-over-year. These increases in cash provided by operating activities wereFinancing segments, partially offset by lower distributions from Sisecam Wyoming year-over-year.
Cash flows used in financing activities decreased $0.9$22.5 million, from $89.4$366.0 million in the year ended December 31, 2020 to $88.5 million in the year ended December 31, 2021 primarily due to a $10.8 million decrease in cash distributions to preferred unitholders as we paid one-half of our preferred unit distributions in kind through the issuance of 15.6 million preferred units in 2021. Additionally, debt repayments decreased $6.8 million in 2021 as one series of Opco Senior Notes was fully repaidused during the year ended December 31, 2020. 2022 to $343.5 million used during the year ended December 31, 2023 primarily due to the following:
• | $300.0 million of cash used to retire the 2025 Senior Notes in 2022; |
• | $178.8 million of increased borrowings on the Opco Credit Facility in 2023; |
| • | $19.3 million of cash used to redeem the preferred units paid-in-kind in 2022; | |
| • | $9.1 million of decreased cash used for other items, net primarily due to the premiums paid related to the retirement of the 2025 Senior Notes in 2022; and |
• | $8.2 million of decreased cash used for preferred unit distributions as a result of the preferred unit redemptions in 2023. |
These decreases in cash flow used were partially offset by $9.2 million used to settle the exercise of certain of our warrants in 2021 in addition to a $5.8 million increase in distributions to common unitholders and the general partner as we suspended our common unit distribution in the second quarter of 2020.
| • | $178.3 million of cash used to redeem the preferred units in 2023; | |
| • | $223.0 million of cash used to repay a portion of the Opco Credit Facility in 2023; | |
| • | $56.1 million of cash used to settle certain of our warrants in 2023; and | |
| • | $35.5 million of increased cash distributions to common unitholders and the general partner as a result of the special cash distribution of $2.43/unit made in the first quarter of 2023 in addition to increasing our common unit distributions to $0.75/unit beginning in the second quarter of 2022. |
For discussion of our Cash Flows comparing 20202022 to 2019,2021, refer to our 20202022 Annual Report on Form 10-K filed March 15, 20213, 2023 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, 20212023 and 2020:
| December 31, | |||||||||||
| (In thousands) | 2021 | 2020 | |||||||||
| Current portion of long-term debt, net | $ | 39,102 | $ | 39,055 | |||||||
| Long-term debt, net | 394,443 | 432,444 | |||||||||
| Total debt, net | $ | 433,545 | $ | 471,499 | |||||||
December 31, | ||||||||
(In thousands) | 2023 | 2022 | ||||||
Current portion of long-term debt, net | $ | 30,785 | $ | 39,076 | ||||
Long-term debt, net | 124,273 | 129,205 | ||||||
Total debt, net | $ | 155,058 | $ | 168,281 | ||||
We have been and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information 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, 2021:
| Payments Due by Period | ||||||||||||||||||||||||||||||||||||||||||||
| Debt Obligations (In thousands) | Total | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | |||||||||||||||||||||||||||||||||||||
| NRP: | ||||||||||||||||||||||||||||||||||||||||||||
Debt principal payments (1) | $ | 300,000 | $ | — | $ | — | $ | — | $ | 300,000 | $ | — | $ | — | ||||||||||||||||||||||||||||||
Debt interest payments (1) | 95,813 | 27,375 | 27,375 | 27,375 | 13,688 | — | — | |||||||||||||||||||||||||||||||||||||
| Opco: | ||||||||||||||||||||||||||||||||||||||||||||
Debt principal payments (including current maturities) (2) | 138,484 | 39,396 | 39,396 | 31,028 | 14,332 | 14,332 | — | |||||||||||||||||||||||||||||||||||||
Debt interest payments (3) | 16,925 | 7,131 | 4,895 | 2,724 | 1,450 | 725 | — | |||||||||||||||||||||||||||||||||||||
| Total | $ | 551,222 | $ | 73,902 | $ | 71,666 | $ | 61,127 | $ | 329,470 | $ | 15,057 | $ | — | ||||||||||||||||||||||||||||||
Payments Due by Period | ||||||||||||||||||||||||||||
Debt Obligations (In thousands) | Total | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | |||||||||||||||||||||
Opco: | ||||||||||||||||||||||||||||
Debt principal payments (including current maturities) (1) | $ | 155,525 | $ | 31,028 | $ | 14,332 | $ | 14,331 | $ | 95,834 | $ | - | $ | — | ||||||||||||||
Debt interest payments (2) | 4,899 | 2,724 | 1,450 | 725 | — | — | — | |||||||||||||||||||||
Total | $ | 160,424 | $ | 33,752 | $ | 15,782 | $ | 15,056 | $ | 95,834 | $ | — | $ | — | ||||||||||||||
(1) | The amounts indicated in the table include principal due on Opco’s senior notes and credit facility. |
(2) | The amounts indicated in the table include interest due on Opco’s senior notes. | |||||||||||||
Preferred Units and interest due on NRP’s 2025 Senior Notes.
As of the Opco Credit Facility, which matures in April 2023. At December 31, 2021 we did not have any borrowings2023 there were 71,666 preferred units outstanding. As of December 31, 2022 there were 250,000 preferred units outstanding. As of December 31, 2023 there were 1,540,000 warrants with a strike price of $34.00 outstanding. As of December 31, 2022 there were 3,002,500 warrants outstanding, under the Opco Credit Facilitywhich included warrants to purchase 752,500 common units at a strike price of $22.81 and had $100.0 millionwarrants to purchase 2,250,00 common units with a strike price of $34.00. For more information on our preferred units and warrants, see "Item 8. Financial Statements and Supplementary Data—Note 4. Class A Convertible Preferred Units and Warrants" in available borrowing capacity.
Inflation
Despite rising costs beginning in 2021 and continuing into 2023, inflation did not have a material impact on operations for the years ended December 31, 2021, 20202023, 2022 and 2019.
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.Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See "
Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies" in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significant accounting policies. The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates.Revenues
Mineral Rights Segment Revenues
Royalty-based leases.
Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms. For these types of leases, the lessees generally make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral mined and sold. Most of our coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts, either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally range from three to five years.We have defined our coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell our coal or aggregates over the lease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production would exceed consideration expected to be received from minimum payments over the lease term.
As a result of this evaluation, revenue recognition from our royalty-based leases is based on either production or minimum payments as follows:
• | Production Leases: Leases for which we expect that consideration from production will be greater than consideration from minimums over the lease term. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, we recognize breakage revenue from minimums when we determine that recoupment is remote. This breakage revenue is included in production lease minimum revenues. |
• | Minimum Leases: Leases for which we expect that consideration from minimums will be greater than consideration from production over the lease term. Revenue for these leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues. |
This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease.
Mineral Rights
Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated economic tonnage as estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of our economic tonnage include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statistical analysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of economic tonnage, including many factors beyond our control. Estimates of economically recoverable tonnage depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results.
Asset Impairment
We have developed procedures to evaluate our long-lived assets, including intangible assets, for possible impairment periodically or whenever events or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific events such as a reduction in economically recoverable tons or production ceasing on a property for an extended period. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the asset's net book value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants.
We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.
Recent Accounting Standards
In November 2023, the FASB issued ASU No. 2023-07—Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures ("ASU 2023-07"). The amendments in ASU 2023-07 improve reportable segment disclosure requirements, primarily through enhanced disclosures about segment expenses. The guidance is effective for annual and interim periods beginning after December 15, 2023 and is to be adopted retrospectively to all prior periods presented in the financial statements. We do not believe that any other recently issued, but not yet effective, accounting standards, if currently adopted, wouldexpect the adoption of ASU 2023-07 to have a material effect on our financial statements.Consolidated Financial Statements.
We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:
Commodity Price Risk
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices. Historically, coal prices have been volatile, with prices fluctuating widely, and are likely to continue to be volatile. Depressed prices in the future would have a smaller reporting companynegative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenues and could potentially trigger an impairment of our coal properties or a violation of certain financial debt covenants. Because substantially all our reserves are coal, changes in coal prices have a more significant impact on our financial results.
We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees' failure to negotiate long-term contracts could adversely affect the year endedstability and profitability of our lessees' operations and adversely affect our future financial results. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices.
The market price of soda ash and energy costs directly affects the profitability of Sisecam Wyoming's operations. If the market price for soda ash declines, Sisecam Wyoming's sales revenues will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile and are likely to remain volatile in the future.
The following table shows the fluctuations of our commodity prices over the past three years:
| 2023 | 2022 | 2021 | ||||||||||
| Combined average coal royalty revenue per ton | $ | 6.83 | $ | 6.90 | $ | 4.47 | ||||||
| Soda ash average sales price per short ton | $ | 284.97 | $ | 270.42 | $ | 191.97 | ||||||
Interest Rate Risk
Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to variable interest rates based upon SOFR. At December 31, 2021,30, 2023, we are not requiredhad $95.8 million in borrowings outstanding under the Opco Credit Facility. If interest rates were to include this disclosure inincrease by 1%, annual interest expense would increase approximately $9.6 million, assuming the same principal amount remained outstanding during the year.
Fair Value of Financial Assets and Liabilities
Our financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. We use available market data and valuation methodologies to estimate the fair value of our 2021 Form 10-K.
The following table shows the carrying value and estimated fair value of our debt and contract receivable:
December 31, | ||||||||||||||||||||
2023 | 2022 | |||||||||||||||||||
Carrying | Estimated | Carrying | Estimated | |||||||||||||||||
(In thousands) | Fair Value Hierarchy Level | Value | Fair Value | Value | Fair Value | |||||||||||||||
Debt: | ||||||||||||||||||||
Opco Senior Notes (1) | 3 | $ | 59,224 | $ | 56,533 | $ | 98,281 | $ | 96,060 | |||||||||||
Opco Credit Facility (2) | 3 | 95,834 | 95,384 | 70,000 | 70,000 | |||||||||||||||
Assets: | ||||||||||||||||||||
Contract receivable, net (current and long-term) (3) | 3 | $ | 28,946 | $ | 24,492 | $ | 31,371 | $ | 24,833 | |||||||||||
(1) | The fair value of the Opco Senior Notes was estimated by management utilizing the present value replacement method incorporating the interest rate of the Opco Credit Facility. |
(2) | The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. |
(3) | The fair value of the Partnership's contract receivable was determined based on the present value of future cash flow projections related to the underlying asset at a discount rate of 15% at December 31, 2023 and 2022. |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |||||||||
| 44 | |||||||||
Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm (PCAOB ID 34) | |||||||||
To the Partners of Natural Resource Partners L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. (the Partnership) as of December 31, 20212023 and 2020,2022, the related consolidated statements of comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2021,2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the reportreports of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 20212023 and 2020,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021,2023, in conformity with U.S. generally accepted accounting principles.
We did not audit the financial statements of Sisecam Wyoming LLC (Sisecam Wyoming), a limited liability company in which the Partnership has a 49% interest. In the consolidated financial statements, the Partnership’s investment in Sisecam Wyoming is stated at $276$277 million and $263$306 million as of December 31, 20212023 and 2020,2022, respectively, and the Partnership’s equity in the net income of Sisecam Wyoming is stated at $73 million in 2023, $60 million in 2022 and $22 million in 2021, $11 million in 2020 and $47 million in 2019.2021. Those statements were audited by other auditors whose report hasreports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Sisecam Wyoming, is based solely on the reportreports of the other auditors.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2021,2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 15, 20227, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidatedfinancial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates.
Description of the Matter | At December 31, Auditing the Partnership’s impairment | ||||||
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Partnership’s impairment assessment process. We tested controls over the Partnership’s process for identifying and evaluating potential To test the Partnership’s mineral rights impairment assessment, our audit procedures included, among others, making inquiries of management (including personnel in operations) to understand changes in business, and evaluating the significant judgments | ||||||
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2002.
Houston, Texas
March 15, 2022
Sisecam Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Sisecam Wyoming LLC (the "Company"“Company”) as of December 31, 20212023 and 2020,2022, the related statements of operations and comprehensive income, members'members’ equity, and cash flows for each of the three years in the periodthen ended, December 31, 2021, and the related notes that are included in Exhibit 99.1 (collectively referred to as the "financial statements"“financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as ofat December 31, 20212023 and 2020,2022, and the results of its operations and its cash flows for each of the three years in the periodthen ended, December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company'sCompany’s management. Our responsibility is to express an opinion on the Company'sCompany’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB)(“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-periodcurrent period audit of the financial statements that was communicated or required to be communicated to the audit committeeBoard of Managers and thatthat: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinionopinions on the critical audit matter or on the accounts or disclosures to which it relates.
Agreements and Transactions with Affiliates – Refer to Notes 1, 2, 8, 12,
As presented in the financial statements and further described in Note 13 to the financial statements,
We identified the Company’s identification of upstream affiliate relationships,agreements and transactions and commitments and contingencies originating outside of the Ciner Enterprises, Inc. group and the impact of such matters on the financial statements representswith affiliates as a critical audit matter because of the increasedmatter. Management’s judgment was required in performing cost allocations and auditing these elements involved especially challenging auditor judgment necessary to perform audit procedures related to these matters and evaluate the results of those procedures.
The primary procedures we performed to address this critical audit matter included:
| • | Testing the Company’s affiliate listing for the year ended December 31, 2023, including testing the completeness and accuracy of the identification of the Company’s affiliate relationships, transactions, and commitments and contingencies originating outside of the Company by: | |
| (i) reading internal minutes, publicly available financial filings and news sources related to the Company and its affiliates outside of the Company, | ||
| (ii) confirming with the Company’s ultimate parent companies the affiliate relationships, transactions, and commitments and contingencies are identified and disclosed by the Company, | ||
| (iii) testing the accuracy of the cost allocations to ensure they are being recorded in the appropriate financial statement accounts. | ||
/s/ BDO USA, P.C.
We have served as the following, among others:Company's auditor since 2022.
Charlotte, North Carolina
March 7, 2024
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers regarding affiliate relationships, transactions and commitmentsMembers of
Sisecam Wyoming LLC
Atlanta, Georgia
Opinion on the Financial Statements
We have audited the accompanying statements of operations and contingencies.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audit. We confirmedare a public accounting firm registered with the Company's ultimate parent companies that the affiliate relationships, transactions,Public Company Accounting Oversight Board (United States) (PCAOB) and commitments and contingencies identified and disclosed byare required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were complete.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 15, 2022
We have servedbegan serving as the Company’sCompany's auditor sincein 2008.
CONSOLIDATED BALANCE SHEETS
December 31, | ||||||||
(In thousands, except unit data) | 2023 | 2022 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 11,989 | $ | 39,091 | ||||
Accounts receivable, net | 41,086 | 42,701 | ||||||
Other current assets, net | 2,218 | 1,822 | ||||||
Total current assets | $ | 55,293 | $ | 83,614 | ||||
Land | 24,008 | 24,008 | ||||||
Mineral rights, net | 394,483 | 412,312 | ||||||
Intangible assets, net | 13,682 | 14,713 | ||||||
Equity in unconsolidated investment | 276,549 | 306,470 | ||||||
Long-term contract receivable, net | 26,321 | 28,946 | ||||||
Other long-term assets, net | 7,540 | 7,068 | ||||||
Total assets | $ | 797,876 | $ | 877,131 | ||||
LIABILITIES AND CAPITAL | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 885 | $ | 1,992 | ||||
Accrued liabilities | 12,987 | 11,916 | ||||||
Accrued interest | 584 | 989 | ||||||
Current portion of deferred revenue | 4,599 | 6,256 | ||||||
Current portion of long-term debt, net | 30,785 | 39,076 | ||||||
Total current liabilities | $ | 49,840 | $ | 60,229 | ||||
Deferred revenue | 38,356 | 40,181 | ||||||
Long-term debt, net | 124,273 | 129,205 | ||||||
Other non-current liabilities | 7,172 | 5,472 | ||||||
Total liabilities | $ | 219,641 | $ | 235,087 | ||||
Commitments and contingencies (see Note 15) | ||||||||
Class A Convertible Preferred Units (71,666 and 250,000 units issued and outstanding at December 31, 2023 and 2022, respectively, at $1,000 par value per unit; liquidation preference of $1,850 per unit at December 31, 2023 and 2022) (See Note 4) | $ | 47,181 | $ | 164,587 | ||||
Partners’ capital | ||||||||
Common unitholders’ interest (12,634,642 and 12,505,996 units issued and outstanding at December 31, 2023 and 2022, respectively) | $ | 503,076 | $ | 404,799 | ||||
General partner’s interest | 8,005 | 5,977 | ||||||
Warrant holders’ interest | 23,095 | 47,964 | ||||||
Accumulated other comprehensive income (loss) | (3,122 | ) | 18,717 | |||||
Total partners' capital | $ | 531,054 | $ | 477,457 | ||||
Total liabilities and partners' capital | $ | 797,876 | $ | 877,131 | ||||
| December 31, | |||||||||||
| (In thousands, except unit data) | 2021 | 2020 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 135,520 | $ | 99,790 | |||||||
| Accounts receivable, net | 24,538 | 12,322 | |||||||||
| Other current assets, net | 2,723 | 5,080 | |||||||||
| Total current assets | $ | 162,781 | $ | 117,192 | |||||||
| Land | 24,008 | 24,008 | |||||||||
| Mineral rights, net | 437,697 | 460,373 | |||||||||
| Intangible assets, net | 16,130 | 17,459 | |||||||||
| Equity in unconsolidated investment | 276,004 | 262,514 | |||||||||
| Long-term contract receivable, net | 31,371 | 33,264 | |||||||||
| Other long-term assets, net | 5,832 | 7,067 | |||||||||
| Total assets | $ | 953,823 | $ | 921,877 | |||||||
| LIABILITIES AND CAPITAL | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable | $ | 1,956 | $ | 1,385 | |||||||
| Accrued liabilities | 10,297 | 7,733 | |||||||||
| Accrued interest | 1,213 | 1,714 | |||||||||
| Current portion of deferred revenue | 11,817 | 11,485 | |||||||||
| Current portion of long-term debt, net | 39,102 | 39,055 | |||||||||
| Total current liabilities | $ | 64,385 | $ | 61,372 | |||||||
| Deferred revenue | 50,045 | 50,069 | |||||||||
| Long-term debt, net | 394,443 | 432,444 | |||||||||
| Other non-current liabilities | 5,018 | 5,131 | |||||||||
| Total liabilities | $ | 513,891 | $ | 549,016 | |||||||
| Commitments and contingencies (see Note 15) | |||||||||||
| Class A Convertible Preferred Units (269,321 and 253,750 units issued and outstanding at December 31, 2021 and 2020, respectively, at $1,000 par value per unit; liquidation preference of $1,850 per unit at December 31, 2021 and $1,700 per unit per unit at December 31, 2020) | $ | 183,908 | $ | 168,337 | |||||||
| Partners’ capital | |||||||||||
| Common unitholders’ interest (12,351,306 and 12,261,199 units issued and outstanding at December 31, 2021 and 2020, respectively) | $ | 203,062 | $ | 136,927 | |||||||
| General partner’s interest | 1,787 | 459 | |||||||||
| Warrant holders’ interest | 47,964 | 66,816 | |||||||||
| Accumulated other comprehensive income | 3,211 | 322 | |||||||||
| Total partners' capital | $ | 256,024 | $ | 204,524 | |||||||
| Total liabilities and partners' capital | $ | 953,823 | $ | 921,877 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, | ||||||||||||
(In thousands, except per unit data) | 2023 | 2022 | 2021 | |||||||||
Revenues and other income | ||||||||||||
Royalty and other mineral rights | $ | 278,733 | $ | 307,013 | $ | 185,196 | ||||||
Transportation and processing services | 14,923 | 21,072 | 9,052 | |||||||||
Equity in earnings of Sisecam Wyoming | 73,397 | 59,795 | 21,871 | |||||||||
Gain on asset sales and disposals | 2,956 | 1,082 | 245 | |||||||||
Total revenues and other income | $ | 370,009 | $ | 388,962 | $ | 216,364 | ||||||
Operating expenses | ||||||||||||
Operating and maintenance expenses | $ | 32,315 | $ | 34,903 | $ | 27,049 | ||||||
Depreciation, depletion and amortization | 18,489 | 22,519 | 19,075 | |||||||||
General and administrative expenses | 26,111 | 21,852 | 17,360 | |||||||||
Asset impairments | 556 | 4,457 | 5,102 | |||||||||
Total operating expenses | $ | 77,471 | $ | 83,731 | $ | 68,586 | ||||||
Income from operations | $ | 292,538 | $ | 305,231 | $ | 147,778 | ||||||
Other expenses, net | ||||||||||||
Interest expense, net | $ | (14,103 | ) | $ | (26,274 | ) | $ | (38,876 | ) | |||
Loss on extinguishment of debt | — | (10,465 | ) | — | ||||||||
Total other expenses, net | $ | (14,103 | ) | $ | (36,739 | ) | $ | (38,876 | ) | |||
Net income | $ | 278,435 | $ | 268,492 | $ | 108,902 | ||||||
Less: income attributable to preferred unitholders | (16,719 | ) | (30,000 | ) | (31,609 | ) | ||||||
Less: redemption of preferred units | (60,929 | ) | — | — | ||||||||
Net income attributable to common unitholders and the general partner | $ | 200,787 | $ | 238,492 | $ | 77,293 | ||||||
Net income attributable to common unitholders | $ | 196,771 | $ | 233,722 | $ | 75,747 | ||||||
Net income attributable to the general partner | 4,016 | 4,770 | 1,546 | |||||||||
Net income per common unit (see Note 6) | ||||||||||||
Basic | $ | 15.59 | $ | 18.72 | $ | 6.14 | ||||||
Diluted | 13.08 | 13.39 | 4.81 | |||||||||
Net income | $ | 278,435 | $ | 268,492 | $ | 108,902 | ||||||
Comprehensive income (loss) from unconsolidated investment and other | (21,839 | ) | 15,506 | 2,889 | ||||||||
Comprehensive income | $ | 256,596 | $ | 283,998 | $ | 111,791 | ||||||
| For the Year Ended December 31, | |||||||||||||||||
| (In thousands, except per unit data) | 2021 | 2020 | 2019 | ||||||||||||||
| Revenues and other income | |||||||||||||||||
| Royalty and other mineral rights | $ | 185,196 | $ | 120,166 | $ | 191,069 | |||||||||||
| Transportation and processing services | 9,052 | 8,845 | 19,279 | ||||||||||||||
| Equity in earnings of Sisecam Wyoming | 21,871 | 10,728 | 47,089 | ||||||||||||||
| Gain on asset sales and disposals | 245 | 581 | 6,498 | ||||||||||||||
| Total revenues and other income | $ | 216,364 | $ | 140,320 | $ | 263,935 | |||||||||||
| Operating expenses | |||||||||||||||||
| Operating and maintenance expenses | $ | 27,049 | $ | 24,795 | $ | 32,738 | |||||||||||
| Depreciation, depletion and amortization | 19,075 | 9,198 | 14,932 | ||||||||||||||
| General and administrative expenses | 17,360 | 14,293 | 16,730 | ||||||||||||||
| Asset impairments | 5,102 | 135,885 | 148,214 | ||||||||||||||
| Total operating expenses | $ | 68,586 | $ | 184,171 | $ | 212,614 | |||||||||||
| Income (loss) from operations | $ | 147,778 | $ | (43,851) | $ | 51,321 | |||||||||||
| Other expenses, net | |||||||||||||||||
| Interest expense, net | $ | (38,876) | $ | (40,968) | $ | (47,453) | |||||||||||
| Loss on extinguishment of debt | — | — | (29,282) | ||||||||||||||
| Total other expenses, net | $ | (38,876) | $ | (40,968) | $ | (76,735) | |||||||||||
| Net income (loss) from continuing operations | $ | 108,902 | $ | (84,819) | $ | (25,414) | |||||||||||
| Income from discontinued operations | — | — | 956 | ||||||||||||||
| Net income (loss) | $ | 108,902 | $ | (84,819) | $ | (24,458) | |||||||||||
| Less: income attributable to preferred unitholders | (31,609) | (30,225) | (30,000) | ||||||||||||||
| Net income (loss) attributable to common unitholders and the general partner | $ | 77,293 | $ | (115,044) | $ | (54,458) | |||||||||||
| Net income (loss) attributable to common unitholders | $ | 75,747 | $ | (112,743) | $ | (53,369) | |||||||||||
| Net income (loss) attributable to the general partner | 1,546 | (2,301) | (1,089) | ||||||||||||||
| Income (loss) from continuing operations per common unit (see Note 6) | |||||||||||||||||
| Basic | $ | 6.14 | $ | (9.20) | $ | (4.43) | |||||||||||
| Diluted | 4.81 | (9.20) | (4.43) | ||||||||||||||
| Net income (loss) per common unit (see Note 6) | |||||||||||||||||
| Basic | $ | 6.14 | $ | (9.20) | $ | (4.35) | |||||||||||
| Diluted | 4.81 | (9.20) | (4.35) | ||||||||||||||
| Net income (loss) | $ | 108,902 | $ | (84,819) | $ | (24,458) | |||||||||||
| Comprehensive income from unconsolidated investment and other | 2,889 | 2,916 | 868 | ||||||||||||||
| Comprehensive income (loss) | $ | 111,791 | $ | (81,903) | $ | (23,590) | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF PARTNERS’PARTNERS’ CAPITAL
Accumulated | ||||||||||||||||||||||||
Other | Total | |||||||||||||||||||||||
Common Unitholders | General | Warrant | Comprehensive | Partners' | ||||||||||||||||||||
(In thousands) | Units | Amounts | Partner | Holders | Income (Loss) | Capital | ||||||||||||||||||
Balance at December 31, 2020 | 12,261 | $ | 136,927 | $ | 459 | $ | 66,816 | $ | 322 | $ | 204,524 | |||||||||||||
Net income (1) | — | 106,724 | 2,178 | — | — | 108,902 | ||||||||||||||||||
Distributions to common unitholders and the general partner | — | (22,192 | ) | (453 | ) | — | — | (22,645 | ) | |||||||||||||||
Distributions to preferred unitholders | — | (30,519 | ) | (623 | ) | — | — | (31,142 | ) | |||||||||||||||
Issuance of unit-based awards | 90 | — | — | — | — | — | ||||||||||||||||||
Unit-based awards amortization and vesting, net | — | 2,647 | — | — | — | 2,647 | ||||||||||||||||||
Capital contribution | — | — | 32 | — | — | 32 | ||||||||||||||||||
Warrant settlement | — | 9,475 | 194 | (18,852 | ) | — | (9,183 | ) | ||||||||||||||||
Comprehensive income from unconsolidated investment and other | — | — | — | — | 2,889 | 2,889 | ||||||||||||||||||
Balance at December 31, 2021 | 12,351 | $ | 203,062 | $ | 1,787 | $ | 47,964 | $ | 3,211 | $ | 256,024 | |||||||||||||
Net income (2) | — | 263,122 | 5,370 | — | — | 268,492 | ||||||||||||||||||
Distributions to common unitholders and the general partner | — | (33,697 | ) | (687 | ) | — | — | (34,384 | ) | |||||||||||||||
Distributions to preferred unitholders | — | (29,653 | ) | (605 | ) | — | — | (30,258 | ) | |||||||||||||||
Issuance of unit-based awards | 155 | — | — | — | — | — | ||||||||||||||||||
Unit-based awards amortization and vesting, net | — | 1,965 | — | — | — | 1,965 | ||||||||||||||||||
Capital contribution | — | — | 112 | — | — | 112 | ||||||||||||||||||
Comprehensive income from unconsolidated investment and other | — | — | — | — | 15,506 | 15,506 | ||||||||||||||||||
Balance at December 31, 2022 | 12,506 | $ | 404,799 | $ | 5,977 | $ | 47,964 | $ | 18,717 | $ | 477,457 | |||||||||||||
Net income (3) | — | 272,866 | 5,569 | — | — | 278,435 | ||||||||||||||||||
Redemptions of preferred units | — | (59,710 | ) | (1,219 | ) | — | — | (60,929 | ) | |||||||||||||||
Distributions to common unitholders and the general partner | — | (68,510 | ) | (1,398 | ) | — | — | (69,908 | ) | |||||||||||||||
Distributions to preferred unitholders | — | (21,628 | ) | (441 | ) | — | — | (22,069 | ) | |||||||||||||||
Issuance of unit-based awards | 129 | — | — | — | — | — | ||||||||||||||||||
Unit-based awards amortization and vesting, net | — | 5,854 | — | — | — | 5,854 | ||||||||||||||||||
Capital contribution | — | — | 142 | — | — | 142 | ||||||||||||||||||
Warrant settlements | — | (30,595 | ) | (625 | ) | (24,869 | ) | — | (56,089 | ) | ||||||||||||||
Comprehensive loss from unconsolidated investment and other | — | — | — | — | (21,839 | ) | (21,839 | ) | ||||||||||||||||
Balance at December 31, 2023 | 12,635 | $ | 503,076 | $ | 8,005 | $ | 23,095 | $ | (3,122 | ) | $ | 531,054 | ||||||||||||
| Common Unitholders | General Partner | Warrant Holders | Accumulated Other Comprehensive Income (Loss) | Partners' Capital Excluding Non-Controlling Interest | Non-Controlling Interest | Total Capital | |||||||||||||||||||||||||||||||||||||||||
| (In thousands) | Units | Amounts | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 12,249 | $ | 355,113 | $ | 5,014 | $ | 66,816 | $ | (3,462) | $ | 423,481 | $ | (2,935) | $ | 420,546 | ||||||||||||||||||||||||||||||||
Net loss (1) | — | (23,969) | (489) | — | — | (24,458) | — | (24,458) | |||||||||||||||||||||||||||||||||||||||
| Distributions to common unitholders and the general partner | — | (32,487) | (663) | — | — | (33,150) | — | (33,150) | |||||||||||||||||||||||||||||||||||||||
| Distributions to preferred unitholders | — | (29,400) | (600) | — | — | (30,000) | — | (30,000) | |||||||||||||||||||||||||||||||||||||||
| Issuance of unit-based awards | 12 | 486 | — | — | — | 486 | — | 486 | |||||||||||||||||||||||||||||||||||||||
| Unit-based awards amortization and vesting | — | 1,804 | — | — | — | 1,804 | — | 1,804 | |||||||||||||||||||||||||||||||||||||||
| Comprehensive income (loss) from unconsolidated investment and other | — | (76) | 8 | — | 868 | 800 | — | 800 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 12,261 | $ | 271,471 | $ | 3,270 | $ | 66,816 | $ | (2,594) | $ | 338,963 | $ | (2,935) | $ | 336,028 | ||||||||||||||||||||||||||||||||
| Cumulative effect of adoption of accounting standard | — | (3,833) | (78) | — | — | (3,911) | — | (3,911) | |||||||||||||||||||||||||||||||||||||||
Net loss (2) | — | (83,123) | (1,696) | — | — | (84,819) | — | (84,819) | |||||||||||||||||||||||||||||||||||||||
| Distributions to common unitholders and the general partner | — | (16,552) | (338) | — | — | (16,890) | — | (16,890) | |||||||||||||||||||||||||||||||||||||||
| Distributions to preferred unitholders | — | (29,511) | (602) | — | — | (30,113) | — | (30,113) | |||||||||||||||||||||||||||||||||||||||
| Acquisition of non-controlling interest in BRP | — | (4,747) | (97) | — | — | (4,844) | 2,935 | (1,909) | |||||||||||||||||||||||||||||||||||||||
| Unit-based awards amortization and vesting | — | 3,222 | — | — | — | 3,222 | — | 3,222 | |||||||||||||||||||||||||||||||||||||||
| Comprehensive income from unconsolidated investment and other | — | — | — | — | 2,916 | 2,916 | — | 2,916 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 12,261 | $ | 136,927 | $ | 459 | $ | 66,816 | $ | 322 | $ | 204,524 | $ | — | $ | 204,524 | ||||||||||||||||||||||||||||||||
Net income (3) | — | 106,724 | 2,178 | — | — | 108,902 | — | 108,902 | |||||||||||||||||||||||||||||||||||||||
| Distributions to common unitholders and the general partner | — | (22,192) | (453) | — | — | (22,645) | — | (22,645) | |||||||||||||||||||||||||||||||||||||||
| Distributions to preferred unitholders | — | (30,519) | (623) | — | — | (31,142) | — | (31,142) | |||||||||||||||||||||||||||||||||||||||
| Issuance of unit-based awards | 90 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Unit-based awards amortization and vesting | — | 2,647 | — | — | — | 2,647 | — | 2,647 | |||||||||||||||||||||||||||||||||||||||
| Capital contribution | — | — | 32 | — | — | 32 | — | 32 | |||||||||||||||||||||||||||||||||||||||
| Warrant settlement | — | 9,475 | 194 | (18,852) | — | (9,183) | — | (9,183) | |||||||||||||||||||||||||||||||||||||||
| Comprehensive income from unconsolidated investment and other | — | — | — | — | 2,889 | 2,889 | — | 2,889 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 12,351 | $ | 203,062 | $ | 1,787 | $ | 47,964 | $ | 3,211 | $ | 256,024 | $ | — | $ | 256,024 | ||||||||||||||||||||||||||||||||
(1) | Net income includes $31.6 million of income attributable to preferred unitholders that accumulated during the period, of which $31.0 million is allocated to the common unitholders and $0.6 million is allocated to the general partner. | |||||||||||||
| (2) | Net income includes $30.0 million of income attributable to preferred unitholders that accumulated during the period, of which $29.4 million is allocated to the common unitholders and $0.6 million is allocated to the general partner. | |||||||||||||
| (3) | Net income includes $16.7 million of income attributable to preferred unitholders that accumulated during the period, of which $16.4 million is allocated to the common unitholders and $0.3 million is allocated to the general partner. | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31, | ||||||||||||
(In thousands) | 2023 | 2022 | 2021 | |||||||||
Cash flows from operating activities | ||||||||||||
Net income | $ | 278,435 | $ | 268,492 | $ | 108,902 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization | 18,489 | 22,519 | 19,075 | |||||||||
Distributions from unconsolidated investment | 81,478 | 44,835 | 11,270 | |||||||||
Equity earnings from unconsolidated investment | (73,397 | ) | (59,795 | ) | (21,871 | ) | ||||||
Gain on asset sales and disposals | (2,956 | ) | (1,082 | ) | (245 | ) | ||||||
Loss on extinguishment of debt | — | 10,465 | — | |||||||||
Asset impairments | 556 | 4,457 | 5,102 | |||||||||
Bad debt expense | 2,244 | 1,062 | 2,572 | |||||||||
Unit-based compensation expense | 10,910 | 5,773 | 4,039 | |||||||||
Amortization of debt issuance costs and other | 1,303 | 2,410 | 2,265 | |||||||||
Change in operating assets and liabilities: | ||||||||||||
Accounts receivable | (164 | ) | (18,671 | ) | (14,415 | ) | ||||||
Accounts payable | (1,108 | ) | 37 | 570 | ||||||||
Accrued liabilities | (225 | ) | 935 | 3,020 | ||||||||
Accrued interest | (406 | ) | (224 | ) | (501 | ) | ||||||
Deferred revenue | (3,483 | ) | (15,424 | ) | 307 | |||||||
Other items, net | (698 | ) | 1,049 | 1,714 | ||||||||
Net cash provided by operating activities | $ | 310,978 | $ | 266,838 | $ | 121,804 | ||||||
Cash flows from investing activities | ||||||||||||
Proceeds from asset sales and disposals | $ | 2,963 | $ | 1,083 | $ | 249 | ||||||
Return of long-term contract receivable | 2,463 | 1,723 | 2,163 | |||||||||
Capital expenditures | (10 | ) | (118 | ) | — | |||||||
Net cash provided by investing activities | $ | 5,416 | $ | 2,688 | $ | 2,412 | ||||||
Cash flows from financing activities | ||||||||||||
Debt borrowings | $ | 248,834 | $ | 70,000 | $ | — | ||||||
Debt repayments | (262,396 | ) | (339,396 | ) | (39,396 | ) | ||||||
Distributions to common unitholders and the general partner | (69,908 | ) | (34,384 | ) | (22,645 | ) | ||||||
Distributions to preferred unitholders | (22,069 | ) | (30,258 | ) | (15,571 | ) | ||||||
Redemptions of preferred units | (178,334 | ) | — | — | ||||||||
Redemption of preferred units paid-in-kind | — | (19,321 | ) | — | ||||||||
Warrant settlements | (56,089 | ) | — | (9,183 | ) | |||||||
Acquisition of non-controlling interest in BRP | — | — | (1,000 | ) | ||||||||
Other items, net | (3,534 | ) | (12,596 | ) | (691 | ) | ||||||
Net cash used in financing activities | $ | (343,496 | ) | $ | (365,955 | ) | $ | (88,486 | ) | |||
Net increase (decrease) in cash and cash equivalents | $ | (27,102 | ) | $ | (96,429 | ) | $ | 35,730 | ||||
Cash and cash equivalents at beginning of period | 39,091 | 135,520 | 99,790 | |||||||||
Cash and cash equivalents at end of period | $ | 11,989 | $ | 39,091 | $ | 135,520 | ||||||
Supplemental cash flow information: | ||||||||||||
Cash paid for interest | $ | 13,856 | $ | 25,265 | $ | 37,378 | ||||||
Non-cash investing and financing activities: | ||||||||||||
Preferred unit distributions paid-in-kind | $ | — | $ | — | $ | 15,571 | ||||||
| For the Year Ended December 31, | |||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Net income (loss) | $ | 108,902 | $ | (84,819) | $ | (24,458) | |||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities of continuing operations: | |||||||||||||||||
| Depreciation, depletion and amortization | 19,075 | 9,198 | 14,932 | ||||||||||||||
| Distributions from unconsolidated investment | 11,270 | 14,210 | 31,850 | ||||||||||||||
| Equity earnings from unconsolidated investment | (21,871) | (10,728) | (47,089) | ||||||||||||||
| Gain on asset sales and disposals | (245) | (581) | (6,498) | ||||||||||||||
| Loss on extinguishment of debt | — | — | 29,282 | ||||||||||||||
| Income from discontinued operations | — | — | (956) | ||||||||||||||
| Asset impairments | 5,102 | 135,885 | 148,214 | ||||||||||||||
| Bad debt expense | 2,572 | 4,001 | 7,462 | ||||||||||||||
| Unit-based compensation expense | 4,039 | 3,570 | 2,361 | ||||||||||||||
| Amortization of debt issuance costs and other | 2,265 | 1,323 | 3,687 | ||||||||||||||
| Change in operating assets and liabilities: | |||||||||||||||||
| Accounts receivable | (14,415) | 12,853 | (6,035) | ||||||||||||||
| Accounts payable | 570 | 207 | (1,234) | ||||||||||||||
| Accrued liabilities | 3,020 | (2,205) | (3,656) | ||||||||||||||
| Accrued interest | (501) | (602) | (12,029) | ||||||||||||||
| Deferred revenue | 307 | 9,733 | (732) | ||||||||||||||
| Other items, net | 1,714 | (4,477) | 2,218 | ||||||||||||||
| Net cash provided by operating activities of continuing operations | $ | 121,804 | $ | 87,568 | $ | 137,319 | |||||||||||
| Net cash provided by (used in) operating activities of discontinued operations | — | 1,706 | (8) | ||||||||||||||
| Net cash provided by operating activities | $ | 121,804 | $ | 89,274 | $ | 137,311 | |||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Proceeds from asset sales and disposals | $ | 249 | $ | 623 | $ | 6,500 | |||||||||||
| Return of long-term contract receivable | 2,163 | 2,122 | 1,743 | ||||||||||||||
| Acquisition of non-controlling interest in BRP | — | (1,000) | — | ||||||||||||||
| Acquisition of mineral rights | — | — | (22) | ||||||||||||||
| Net cash provided by investing activities of continuing operations | $ | 2,412 | $ | 1,745 | $ | 8,221 | |||||||||||
| Net cash used in investing activities of discontinued operations | — | (65) | (629) | ||||||||||||||
| Net cash provided by investing activities | $ | 2,412 | $ | 1,680 | $ | 7,592 | |||||||||||
| Cash flows from financing activities | |||||||||||||||||
| Debt borrowings | $ | — | $ | — | $ | 300,000 | |||||||||||
| Debt repayments | (39,396) | (46,176) | (463,082) | ||||||||||||||
| Distributions to common unitholders and the general partner | (22,645) | (16,890) | (33,150) | ||||||||||||||
| Distributions to preferred unitholders | (15,571) | (26,363) | (30,000) | ||||||||||||||
| Warrant settlement | (9,183) | — | — | ||||||||||||||
| Acquisition of non-controlling interest in BRP | (1,000) | — | — | ||||||||||||||
| Contributions from (to) discontinued operations | — | 1,641 | (637) | ||||||||||||||
| Other items | (691) | — | (26,436) | ||||||||||||||
| Net cash used in financing activities of continuing operations | $ | (88,486) | $ | (87,788) | $ | (253,305) | |||||||||||
| Net cash provided by (used in) financing activities of discontinued operations | — | (1,641) | 637 | ||||||||||||||
| Net cash used in financing activities | $ | (88,486) | $ | (89,429) | $ | (252,668) | |||||||||||
| Net increase (decrease) in cash and cash equivalents | $ | 35,730 | $ | 1,525 | $ | (107,765) | |||||||||||
| Cash and cash equivalents of continuing operations at beginning of period | 99,790 | 98,265 | 206,030 | ||||||||||||||
| Cash and cash equivalents at end of period | $ | 135,520 | $ | 99,790 | $ | 98,265 | |||||||||||
| For the Year Ended December 31, | |||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Supplemental cash flow information: | |||||||||||||||||
| Cash paid for interest | $ | 37,378 | $ | 39,830 | $ | 58,597 | |||||||||||
| Non-cash investing and financing activities: | |||||||||||||||||
| Plant, equipment, mineral rights and other funded with accounts payable or accrued liabilities | $ | — | $ | 970 | $ | — | |||||||||||
| Preferred unit distributions paid-in-kind | 15,571 | 3,750 | — | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.Organization and Nature of Operations
Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP" or "general partner"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC ("managing general partner"), a Delaware limited liability company. The Partnership engages principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal and other natural resources and owns a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), formerly known as Ciner Wyoming, a trona ore mining and soda ash production business. The Partnership is organized into 2two operating segments further described in
The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through 1one wholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability company whollyindirectly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. SubjectPursuant to the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with Blackstone Inc. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree"), RCM isBlackstone was entitled to appointone of the directors of the Boardboard of Directorsdirectors of GP Natural Resource Partners LLC (the "Board of Directors"). RCM has delegatedIn 2023, NRP repurchased all of Blackstone's preferred units which were subsequently retired and no longer remain outstanding, and all rights of Blackstone related thereto ceased as a result. In connection with the right to appoint one director to Blackstone.repurchase, Blackstone's board designee resigned from the Board of Directors and all members of the Board of Directors are now appointed by RCM.
Basis of Presentation
The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The Consolidated Financial Statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries. The Partnership has an equity investment in Sisecam Wyoming through which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the investee’s activities and is accounted for using the equity method. Intercompany transactions and balances have been eliminated. Certain reclassificationsReclassifications have been made to prior year amounts in the Notes to Consolidated Financial Statements to conform with current year presentation. These reclassifications had no impact on previously reported total assets, total liabilities, partners' capital, net income, (loss) or cash flows from operating, investing or financing activities.
Use of Estimates
Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities on the accompanying Consolidated Balance Sheets, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses on the accompanying Consolidated Statements of Comprehensive Income (Loss) during the reporting period. Actual results could differ from those estimates. The most significant estimates pertain to coal and aggregates mineral rights and related cash flow estimates which are used to compute depreciation, depletion and amortization and impairments of coal and aggregates properties and related intangible assets and commitments and contingencies.
Fair Value
The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See
Note 12. Fair Value Measurements for further details.There are three levels of inputs that may be used to measure fair value:
• | Level 1—Quoted prices in active markets for identical assets or liabilities. |
• | Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. |
• | Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial assets and liabilities whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation. |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Cash and Cash Equivalents
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents
Allowance for Doubtful Accounts
The Partnership records an allowance for doubtful accounts for its accounts receivable and notes receivable comprised of estimated credit risk and non-credit risk (e.g., legal disputes) losses. Receivables are written off when collection efforts are exhausted and future recovery is doubtful. The Partnership includes an allowance for current expected credit losses ("CECL") on its financial assets based on the loss-rate method. NRP assesses the likelihood of collection of its receivables utilizing historical loss rates, current market conditions, that include the estimated impact of the global COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers and properties. See
Mineral Rights
Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated economic tonnage therein.
Intangible Assets
The Partnership’s intangible assets consist of mineral royalty and transportation contracts that at acquisition were more favorable for the Partnership than prevailing market rates, known as above-market contracts. The estimated fair value of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis by asset based upon minerals mined or transported in relation to the net book value of the intangible asset and estimated economic tonnage expected to be mined or transported during the above-market contract term.
Asset Impairment
The Partnership has developed procedures to evaluate its long-lived assets, including intangible assets, for possible impairment periodically or whenever events or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific events such as a reduction in economically recoverable tons or production ceasing on a property for an extended period. This analysis is based on historic,
The Partnership evaluates its equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices (Level 1)1), or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants (Level 3)3), plus market analysis of comparable assets owned by the investee, if appropriate (Level 3)3).
Accrued Liabilities
Included in accrued liabilities on the Partnership's Consolidated Balance Sheets at December 31, 20212023 were $7.7$10.3 million of accrued employee costs and $2.6$2.7 million of other accrued liabilities, which includes property taxes. These amounts were $3.7$9.5 million and $4.0$2.4 million of accrued employee costs and other accrued liabilities,property taxes, respectively, at December 31, 2020. Other accrued liabilities at December 31, 2020 primarily included property taxes.2022.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Revenue Recognition
Mineral Rights Segment Revenues
Royalty-based leases.
ApproximatelyThe Partnership has defined its coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell its coal or aggregates over the lease term. NRP then evaluated the likelihood that consideration it expected to receive from its lessees resulting from production would exceed consideration expected to be received from minimum payments over the lease term.
As a result of this evaluation, revenue recognition from the Partnership's royalty-based leases is based on either production or minimum payments as follows:
• | Production Leases: Leases for which the Partnership expects that consideration from production will be greater than consideration from minimums over the lease term. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, NRP recognizes breakage revenue from minimums when NRP determines that recoupment is remote. This breakage revenue is included in production lease minimum revenues. |
• | Minimum Leases: Leases for which the Partnership expects that consideration from minimums will be greater than consideration from production over the lease term. Revenue for these leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues. |
This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease.
Oil and gas related revenues consist of revenues from royalties and overriding royalties and are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenues from those sales. Also, included within oil and gas royalty revenues are lease bonus payments, which are generally paid upon the execution of a lease. The Partnership also has overriding royalty revenue interests in certain coal and aggregates mineral rights. Revenue from these interests is recognized over time based on when the coal is sold.
Carbon neutral initiatives. Revenues related to the sale of NRP'sconsideration for carbon offset creditsneutral initiatives that are recognized at a point in time upon executionsatisfaction of the transaction.
Wheelage revenues.
Revenues related to fees collected per ton to transport foreign coal across property owned by the Partnership that is recognized over time as transportation across the property occurs.Other revenues.
Other revenuesTransportation and processing services revenues.
ThePartnership owns transportation and processing infrastructure that is leased to third parties for throughput fees. Revenue is recognized over time based on the coal tons transported over the beltlines or processed through the facilities.Contract Modifications
Contract modifications that impact goods or services or the transaction price are evaluated in accordance with ASC 606. A majority of the Partnership's contract modifications pertain to its coal and aggregates royalty contracts and include, but are not limited to, extending the lease term, changes to royalty rates, floor prices or minimum consideration, assignment of the contract or forfeiture of recoupment rights. Consideration received in conjunction with a modification of an ongoing lease will be deferred and recognized straight-line over the remaining term of the contract. Consideration received to assign a lease to another party and related forfeited minimums will be recognized immediately upon the termination of the contract. Fees from contract modifications are recognized in lease amendment revenues within royalty and other mineral rights revenues on the Consolidated Statements of Comprehensive Income (Loss) while modifications in royalty rates and minimums will be recognized prospectively in accordance with the above lease classification.
Contract Assets and Liabilities from Contracts with Customers
Contract assets include receivables from contracts with customers and are recorded when the right to consideration becomes unconditional. Receivables are recognized when the minimums are contractually owed, production occurs or minimums accrued for based on the passage of time.
Contract liabilities represent minimum consideration received, contractually owed or earned based on the passage of time. The current portion of deferred revenue relates to deferred revenue on minimum leases and lease amendment fees that are to be recognized as revenue on a straight-line basis over the next twelve months. The long-term portion of deferred revenue relates to deferred revenue on production leases and lease amendment fees that are to be recognized as revenue on a straight-line basis beyond the next twelve months. Due to uncertainty in the amount of deferred revenue that will be recouped and recognized as coal royalty revenues from its production leases over the next twelve months, the Partnership is unable to estimate the current portion of deferred revenue.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
Equity in Earnings of Sisecam Wyoming
The Partnership accounts for non-marketable equity investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. The Partnership's 49% investment in Sisecam Wyoming is accounted for using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets is attributed to net tangible assets and is amortized over its estimated useful life. The carrying value in Sisecam Wyoming is recognized in equity in unconsolidated investment on the Partnership's Consolidated Balance Sheets. The Partnership's adjusted share of the earnings or losses of Sisecam Wyoming and amortization of the basis difference is recognized in equity in earnings of Sisecam Wyoming on the Consolidated Statements of Comprehensive Income (Loss).Income. The Partnership decreases its investment for its proportional share of distributions received from Sisecam Wyoming. These cash flows are reported utilizing the cumulative earnings approach. Under this approach, distributions received are considered returns on investment and classified as operating cash inflows unless the cumulative distributions received exceed the Partnership's cumulative equity in earnings. The excess of cumulative distributions received over the Partnership's cumulative equity in earnings are considered returns of investment and classified as investing cash inflows.
Property Taxes
The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in operating and maintenance expenses and in royalty and other mineral rights revenues, respectively, on the Consolidated Statements of Comprehensive Income (Loss).
Unit-Based Compensation
The Partnership has awarded unit-based compensation in the form of equity-based awards and phantom units. Compensation cost is measured atThe Partnership's service and performance-based awards are valued using the closing price of NRP's units as of the grant date for equity-classifiedwhile the Partnership's market-based awards andare valued using a Monte Carlo simulation. Compensation cost is remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. Forfeitures are recognized as they occur. Unit-based compensation expense for all awards is recognized in general and administrative expenses and operating and maintenance expenses on the Consolidated Statements of Comprehensive Income (Loss).Income. See
Deferred Financing Costs
Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s debt. These costs are amortized over the term of the respective line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's revolving credit facility are included in other long-term assets, net on the Partnership's Consolidated Balance Sheets. Deferred financing costs related to the Partnership's note agreements are included as a direct deduction from the carrying amount of the debt liability in current portion of long-term debt, net or long-term debt, net on the Partnership's Consolidated Balance Sheets.
Income Taxes
The Partnership is not subject to federal or material state income taxes as the unitholders are taxed individually on their allocable share of taxable income. Net income (loss) for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the unitholders could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.
Recently Adopted Accounting Standard
On January 1, 2023, NRP adopted Accounting Standards Update ("ASU") 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06)”. The ASU includes targeted improvements to earnings per share, which the Partnership adopted on a modified retrospective basis. The adoption of this ASU did not have a material impact on the Partnership’s Consolidated Financial Statements. See
Recently Issued Accounting Standard
In November 2023, the FASB issued ASU No.2023-07—Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures ("ASU 2023-07"). The amendments in ASU 2023-07 improve reportable segment disclosure requirements, primarily through enhanced disclosures about segment expenses. The guidance is effective for annual and interim periods beginning after December 15, 2023 and will be adopted retrospectively to all prior periods presented in the financial statements. NRP does not expect the adoption of ASU 2023-07 to have a material effect on its Consolidated Financial Statements.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
3.Revenues from Contracts with Customers
The following table represents the Partnership's Mineral Rights segment revenues by major source:
| For the Year Ended December 31, | ||||||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | |||||||||||||||||
| Coal royalty revenues | $ | 104,089 | $ | 51,868 | $ | 109,612 | ||||||||||||||
| Production lease minimum revenues | 14,269 | 21,749 | 24,068 | |||||||||||||||||
| Minimum lease straight-line revenues | 20,564 | 16,796 | 14,910 | |||||||||||||||||
Forest CO2 sequestration revenues | 13,790 | — | — | |||||||||||||||||
| Property tax revenues | 6,028 | 5,786 | 6,287 | |||||||||||||||||
| Wheelage revenues | 10,065 | 7,025 | 5,880 | |||||||||||||||||
| Coal overriding royalty revenues | 4,367 | 4,977 | 13,496 | |||||||||||||||||
| Lease amendment revenues | 4,696 | 3,450 | 7,991 | |||||||||||||||||
| Aggregates royalty revenues | 1,889 | 1,717 | 4,265 | |||||||||||||||||
| Oil and gas royalty revenues | 4,506 | 5,816 | 3,031 | |||||||||||||||||
| Other revenues | 933 | 982 | 1,529 | |||||||||||||||||
Royalty and other mineral rights revenues | $ | 185,196 | $ | 120,166 | $ | 191,069 | ||||||||||||||
Transportation and processing services revenues (1) | 9,052 | 8,845 | 19,279 | |||||||||||||||||
| Total Mineral Rights segment revenues | $ | 194,248 | $ | 129,011 | $ | 210,348 | ||||||||||||||
For the Year Ended December 31, | ||||||||||||
(In thousands) | 2023 | 2022 | 2021 | |||||||||
Coal royalty revenues | $ | 218,011 | $ | 226,956 | $ | 104,089 | ||||||
Production lease minimum revenues | 3,322 | 5,854 | 14,269 | |||||||||
Minimum lease straight-line revenues | 19,389 | 18,792 | 20,564 | |||||||||
Carbon neutral initiative revenues | 2,969 | 8,600 | 13,790 | |||||||||
Property tax revenues | 6,219 | 5,878 | 6,028 | |||||||||
Wheelage revenues | 12,191 | 13,961 | 10,065 | |||||||||
Coal overriding royalty revenues | 2,175 | 3,434 | 4,367 | |||||||||
Lease amendment revenues | 3,070 | 3,201 | 4,696 | |||||||||
Aggregates royalty revenues | 2,876 | 3,299 | 1,889 | |||||||||
Oil and gas royalty revenues | 7,387 | 16,161 | 4,506 | |||||||||
Other revenues | 1,124 | 877 | 933 | |||||||||
Royalty and other mineral rights revenues | $ | 278,733 | $ | 307,013 | $ | 185,196 | ||||||
Transportation and processing services revenues (1) | 14,923 | 21,072 | 9,052 | |||||||||
Total Mineral Rights segment revenues | $ | 293,656 | $ | 328,085 | $ | 194,248 | ||||||
(1) | Transportation and processing services revenues from contracts with customers as defined under ASC 606 was $12.4 million, $17.9 million and $5.4 million for the year ended December 31, 2023, 2022 and 2021, respectively. The remaining transportation and processing services revenues of $2.5 million, $3.2 million and $3.6 million for the year ended December 31, 2023, 2022 and 2021, respectively, related to other NRP-owned infrastructure leased to and operated by third-party operators accounted for under other guidance. See Note 17. Financing Transaction for more information. | |||||||||||||
The following table details the Partnership's Mineral Rights segment receivables and liabilities resulting from contracts with customers:
| December 31, | ||||||||||||||
| (In thousands) | 2021 | 2020 | ||||||||||||
| Receivables | ||||||||||||||
| Accounts receivable, net | $ | 22,277 | $ | 10,193 | ||||||||||
Other current assets, net (1) | 769 | 3,307 | ||||||||||||
Other long-term assets, net (2) | 250 | 525 | ||||||||||||
| Contract liabilities | ||||||||||||||
| Current portion of deferred revenue | $ | 11,817 | $ | 11,485 | ||||||||||
| Deferred revenue | 50,045 | 50,069 | ||||||||||||
December 31, | ||||||||
(In thousands) | 2023 | 2022 | ||||||
Receivables | ||||||||
Accounts receivable, net | $ | 37,206 | $ | 39,004 | ||||
Other current assets, net (1) | 429 | — | ||||||
Other long-term assets, net (2) | — | 75 | ||||||
Contract liabilities | ||||||||
Current portion of deferred revenue | $ | 4,599 | $ | 6,256 | ||||
Deferred revenue | 38,356 | 40,181 | ||||||
(1) | Other current assets, net includes short-term notes receivables from contracts with customers. |
(2) | Other long-term assets, net includes long-term lease amendment fee receivables from contracts with customers. | |||||||||||||
The following table shows the activity related to the Partnership's Mineral Rights segment deferred revenue:
| For the Year Ended December 31, | ||||||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | |||||||||||||||||
| Balance at beginning of period (current and non-current) | $ | 61,554 | $ | 51,821 | $ | 52,553 | ||||||||||||||
| Increase due to minimums and lease amendment fees | 19,842 | 41,557 | 47,038 | |||||||||||||||||
| Recognition of previously deferred revenue | (19,534) | (31,824) | (47,770) | |||||||||||||||||
| Balance at end of period (current and non-current) | $ | 61,862 | $ | 61,554 | $ | 51,821 | ||||||||||||||
For the Year Ended December 31, | ||||||||||||
(In thousands) | 2023 | 2022 | 2021 | |||||||||
Balance at beginning of period (current and non-current) | $ | 46,437 | $ | 61,862 | $ | 61,554 | ||||||
Increase due to minimums and lease amendment fees | 17,526 | 19,073 | 19,842 | |||||||||
Recognition of previously deferred revenue | (21,008 | ) | (34,498 | ) | (19,534 | ) | ||||||
Balance at end of period (current and non-current) | $ | 42,955 | $ | 46,437 | $ | 61,862 | ||||||
The Partnership's non-cancelable annual minimum payments due under the lease terms of its coal and aggregates royalty and overriding royalty leases are as follows as of December 31, 20212023 (in thousands):
Lease Term (1) | Weighted Average Remaining Years | Annual Minimum Payments | ||||||
0 - 5 years | 1.8 | $ | 17,477 | |||||
5 - 10 years | 6.1 | 18,655 | ||||||
10+ years | 12.0 | 25,779 | ||||||
Total | 7.4 | $ | 61,911 | |||||
(1) | Lease term does not include renewal periods. |
Lease Term (1) | Weighted Average Remaining Years | Annual Minimum Payments | ||||||||||||
| 0 - 5 years | 2.6 | $ | 18,341 | |||||||||||
| 5 - 10 years | 4.1 | 6,823 | ||||||||||||
| 10+ years | 13.5 | 28,069 | ||||||||||||
| Total | 8.6 | $ | 53,233 | |||||||||||
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "preferred units") to certain entities controlled by funds affiliated with The Blackstone Group Inc. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree") (together the "preferred purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000 preferred units to the preferred purchasers at a price of $1,000 per preferred unit (the "per unit purchase price"), less a 2.5% structuring and origination fee. The preferred units entitle the preferred purchasers to receive cumulative distributions at a rate of 12% of the purchase price per year, up to one half of which NRP may pay in additional preferred units (such additional preferred units, the "PIK units"). The preferred units have a perpetual term, unless converted or redeemed as described below.
NRP also issued two tranches of warrants (the "warrants") to purchase common units to the preferred purchasers (warrants to purchase 1.75 million common units with a strike price of $22.81 and warrants to purchase 2.25 million common units with a strike price of $34.00). The warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the warrants, NRP may, at its option, elect to settle the warrants in common units or cash, each on a net basis.
After March 2, 2022 and prior to March 2, 2025, the holders of the preferred units may elect to convert up to 33% of the outstanding preferred units in any 12-month12-month period into common units if the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to date notice is provided is greater than $51.00. In such case, the number of common units to be issued upon conversion would be equal to the per unit purchase price plus the value of any accrued and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Rather than have the preferred units convert to common units in accordance with the provisions of this paragraph, NRP would have the option to elect to redeem the preferred units proposed to be converted for cash at a price equal to the per unit purchase price plus the value of any accrued and unpaid distributions.
On or after March 2, 2025, the holders of the preferred units may elect to convert the preferred units to common units at a conversion rate equal to the Liquidation Value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. The “liquidation value” will be an amount equal to the greater of: (1)(1) (a) the per unit purchase price multiplied by (i) prior to March 2, 2020, 1.50, (ii) on or after March 2, 2020 and prior to March 2, 2021, 1.70 and (iii) on or after March 2, 2021, 1.85, less (b)(i) all preferred unit distributions previously made by NRP and (ii) all cash payments previously made in respect of redemption of any PIK units; and (2)(2) the per unit purchase price plus the value of all accrued and unpaid distributions.
To the extent the holders of the preferred units have not elected to convert their preferred units before March 2, 2029, NRP has the right to force conversion of the preferred units at a price equal to the liquidation value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion.
In addition, NRP has the ability to redeem at any time (subject to compliance with its debt agreements) all or any portion of the preferred units and any outstanding PIK units for cash. The redemption price for each outstanding PIK unit is $1,000 plus the value of any accrued and unpaid distributions per PIK unit. The redemption price for each preferred unit is the liquidation value divided by the number of outstanding preferred units. The preferred units are redeemable at the option of the preferred purchasers only upon a change in control.
The terms of the preferred units contain certain restrictions on NRP's ability to pay distributions on its common units. To the extent that either (i) NRP's consolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership Agreement dated March 2, 2017 (the "restated partnership agreement"(the "Restated Partnership Agreement"), is greater than 3.25x, or (ii) the ratio of NRP's Distributable Cash Flow (as defined in the Restated Partnership Agreement) to cash distributions made or proposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarterfour-quarter period), NRP may not increase the quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding preferred units. In addition, if at any time after January 1, 2022, any PIK units are outstanding, NRP may not make distributions on its common units until it has redeemed all PIK units for cash.
The holders of the preferred units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rights with respect to changes of the terms of the preferred units. In addition, pursuant to the Restated Partnership Agreement, Blackstone hashad certain approval rights over certain matters as identified in the restated partnership agreement.Restated Partnership Agreement. GoldenTree also has more limited approval rights that will expand onceexpanded when Blackstone's ownership goesfell below the minimum preferred unit threshold (as defined below). These approval rights are not transferrable without NRP's consent. In addition, the approval rights held by Blackstoneconsent and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of preferred units issued on the closing date, together with all PIK units that have been issued but not redeemed (the "minimum preferred unit threshold").
At the closing, pursuant to the Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights, and Blackstone appointed one director and one observer to the Board of Directors.
NRP also entered into a registration rights agreement (the "preferred unit and warrant registration rights agreement") with the preferred purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the preferred units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of preferred units (the "registration deadlines").units. In addition, the preferred unit and warrant registration rights agreement gives the preferred purchasers piggyback registration and demand underwritten offering rights under certain circumstances. The shelf registration statement to register the common units issuable upon exercise of the warrants became effective on April 20, 2017. If theThe shelf registration statement to register the common units issuable upon conversionexercise of the preferred units is notbecame effective by the applicable registration deadline, NRP will be required to pay the preferred purchasers liquidated damages in the amounts and upon the term set forth in the preferred unit and warrant registration rights agreement.on February 11, 2022.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Accounting for the Preferred Units and Warrants
Classification
The preferred units are accounted for as temporary equity on NRP's Consolidated Balance Sheets due to certain contingent redemption rights that may be exercised at the election of preferred purchasers. The warrants are accounted for as equity on NRP's Consolidated Balance Sheets.
Initial Measurement
The net transaction price was allocated to the preferred units and warrants based on their relative fair values at inception date. NRP allocated the transaction issuance costs to the preferred units and warrants primarily on a pro-rata basis based on their relative inception date allocated values.
Subsequent Measurement
Preferred Units
Subsequent adjustment of the preferred units will not occur until NRP has determined that the conversion or redemption of all or a portion of the preferred units is probable of occurring. Once conversion or redemption becomes probable, of occurring, the carrying amount of the preferred units will be accreted to their redemption value over the period from the date the feature isconversion or redemption becomes probable of occurring to the date the preferred units can first be converted or redeemed.
In 2023, the Partnership received notices from holders of the preferred units exercising their right to either convert or redeem, at the election of NRP, an aggregate of 83,333 preferred units. The Partnership chose to redeem the preferred units for $83.3 million in cash rather than converting them into common units. In 2023, the Partnership also executed negotiated transactions with holders of the preferred units pursuant to which it repurchased and retired an aggregate of 95,001 preferred units for $95.0 million in cash. Of the originally issued 250,000 preferred units, 71,666 preferred units remain outstanding as of December 31, 2023. Following these redemptions and repurchases, the subject preferred units were retired and no longer remain outstanding, and Blackstone ceased to own any preferred units. All rights of Blackstone related to its ownership of preferred units, including Blackstone's right to appoint a board designee have ceased.
Activity related to the preferred units is as follows:
Units | Financial | |||||||
(In thousands, except unit data) | Outstanding | Position | ||||||
Balance at December 31, 2020 | 253,750 | $ | 168,337 | |||||
Distribution paid-in-kind | 15,571 | 15,571 | ||||||
Balance at December 31, 2021 | 269,321 | $ | 183,908 | |||||
Redemption of preferred units paid-in-kind | (19,321 | ) | (19,321 | ) | ||||
Balance at December 31, 2022 | 250,000 | $ | 164,587 | |||||
Redemption of preferred units | (178,334 | ) | (117,406 | ) | ||||
Balance at December 31, 2023 | 71,666 | $ | 47,181 | |||||
| (In thousands, except unit data) | Units Outstanding | Financial Position | ||||||||||||
| Balance at December 31, 2018 and 2019 | 250,000 | $ | 164,587 | |||||||||||
| Distribution paid-in-kind | 3,750 | 3,750 | ||||||||||||
| Balance at December 31, 2020 | 253,750 | $ | 168,337 | |||||||||||
| Distributions paid-in-kind | 15,571 | 15,571 | ||||||||||||
| Balance at December 31, 2021 | 269,321 | $ | 183,908 | |||||||||||
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Warrants
Subsequent adjustment of the warrants will not occur until the warrants are exercised, at which time, NRP may, at its option, elect to settle the warrants in common units or cash, each on a net basis. The net basis will be equal to the difference between the Partnership's common unit price and the strike price of the warrant. Once warrant exercise occurs, the difference between the carrying amount of the warrants and the net settlement amount will be allocated on a pro-rata basis to the common unitholders and general partpartner.
In 2023, the Partnership negotiated transactions with holders of the Partnership's warrants pursuant to which the Partnership repurchased and retired an aggregate of 752,500 warrants with a strike price of $22.81 and 710,000 warrants with a strike price of $34.00 for approximately $56.1 million in cash. As of December 31, 2023, 1,540,000 warrants with a strike price of $34.00 remained outstanding. As of December 31, 2022, 3,002,500 warrants remained outstanding, which included warrants to purchase 752,500 common units at a strike price of $22.81 and warrants to purchase 2,250,00 common units at a strike price of $34.00. These warrants had a $23.1 million and ner. $48.0 million carrying value included in warrant holders' interest within partners' capital on the Partnership's Consolidated Balance Sheets at December 31, 2023 and December 31, 2022, respectively.
On November 10, 2021 (the(the "exercise date"), Blackstone exercised all of its 997,500 warrants with a strike price of $22.81 and NRP settled the warrants in cash on a net basis. NRP delivered the net cash settlement amount of $9.2 million. The 15-day15-day VWAP ending on the business day prior to the exercise date was $32.02.
Activity related to the warrants is as follows:
| (In thousands, except warrant data) | Warrants Outstanding | Financial Position | ||||||||||||
| Balance at December 31, 2018, 2019 and 2020 | 4,000,000 | $ | 66,816 | |||||||||||
| Warrant settlement | (997,500) | (18,852) | ||||||||||||
| Balance at December 31, 2021 | 3,002,500 | $ | 47,964 | |||||||||||
Warrants | Financial | |||||||
(In thousands, except warrant data) | Outstanding | Position | ||||||
Balance at December 31, 2020 | 4,000,000 | $ | 66,816 | |||||
Warrant settlement | (997,500 | ) | (18,852 | ) | ||||
Balance at December 31, 2021 and 2022 | 3,002,500 | $ | 47,964 | |||||
Warrant settlement | (1,462,500 | ) | (24,869 | ) | ||||
Balance at December 31, 2023 | 1,540,000 | $ | 23,095 | |||||
On January 29, 2024 (the "January 2024 exercise date"), holders of the Partnership's warrants exercised 462,165 warrants at a strike price of $34.00. The Partnership settled the warrants on a net basis with $10.0 million in cash and 198,767 common units. The 15-day VWAP ending on the business day prior to the January 2024 exercise date was $97.62. On February 7, 2024 (the "February 7, 2024 exercise date"), holders of the Partnership's warrants exercised 128,750 warrants at a strike price of $34.00. The Partnership settled the warrants on a net basis with $8.0 million in cash. The 15-day VWAP ending on the business day prior to the February 7, 2024 exercise date was $96.29. On February 8, 2024 (the "February 8, 2024 exercise date"), holders of the Partnership's warrants exercised 128,750 warrants at a strike price of $34.00. The 15-day VWAP ending on the business day prior to the February 8, 2024 exercise date was $95.63. The Partnership settled these warrants on a net basis with $7.9 million in cash. On February 14, 2024 (the "February 14, 2024 exercise date"), holders of the Partnership's warrants exercised 500,000 warrants at a strike price of $34.00. The 15-day VWAP ending on the business day prior to the February 14, 2024 exercise date was $93.47. The Partnership settled these warrants on a net basis with $29.7 million in cash. Following these transactions, of the originally issued 4,000,000 warrants, 320,335 warrants with a strike price of $34.00 remain outstanding. As a result of these settlements, warrant holders' interest on the Partnership's Statement of Partners' Capital decreased by $18.3 million during the first quarter of 2024.
Certain embedded features within the preferred unit and warrant purchase agreement are accounted for at fair value and are remeasured each quarter. See
Note 12. Fair Value Measurements for further information regarding valuation of these embedded derivatives.NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
5.Common and Preferred Unit Distributions
The Partnership makes distributions to common and preferred unitholders on a quarterly basis, subject to approval by the Board of Directors. NRP recognizes both common unit and preferred unit distributions on the date the distribution is declared.
Distributions made on the common units and the general partner's general partner ("GP") interest are made on a pro-rata basis in accordance with their relative percentage interests in the Partnership. The general partner is entitled to receive 2% of such distributions.
Income (loss) available to common unitholders and the general partner is reducedadjusted by preferred unit distributions that accumulated during the period. NRP reducedadjusted net income (loss) available to common unitholders and the general partner by $31.6$16.7 million, $30.2$30.0 million and $30.0$31.6 million during the year ended December 31, 2021, 20202023, 2022 and 2019,2021, respectively as a result of accumulated preferred unit distributions earned during the period.
The following table shows the distributions declared and paid to common and preferred unitholders during the year
| Cash Distributions | Paid-in-kind Distributions | |||||||||||||||||||||||||||||||||||||
| Common Units | Preferred Units | |||||||||||||||||||||||||||||||||||||
| Date Paid | Period Covered by Distribution | Distribution per Unit | Total Distribution (1) (In thousands) | Distribution per Unit | Total Distribution (In thousands) | Total Distribution (In units) | ||||||||||||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||||||||||||||
| February 2021 | October 1 - December 31, 2020 | $ | 0.45 | $ | 5,630 | $ | 15.00 | $ | 3,806 | 3,806 | ||||||||||||||||||||||||||||
| May 2021 | January 1 - March 31, 2021 | 0.45 | 5,672 | 15.00 | 3,864 | 3,864 | ||||||||||||||||||||||||||||||||
| August 2021 | April 1 - June 30, 2021 | 0.45 | 5,671 | 15.00 | 3,921 | 3,921 | ||||||||||||||||||||||||||||||||
| November 2021 | July 1 - September 30, 2021 | 0.45 | 5,672 | 15.00 | 3,980 | 3,980 | ||||||||||||||||||||||||||||||||
| 2020 | ||||||||||||||||||||||||||||||||||||||
| February 2020 | October 1 - December 31, 2019 | $ | 0.45 | $ | 5,630 | $ | 30.00 | $ | 7,500 | — | ||||||||||||||||||||||||||||
| May 2020 | January 1 - March 31, 2020 | — | — | 15.00 | 3,750 | 3,750 | ||||||||||||||||||||||||||||||||
June 2020 (2) | January 1 - March 31, 2020 | — | — | 15.45 | 3,863 | — | ||||||||||||||||||||||||||||||||
| August 2020 | April 1 - June 30, 2020 | 0.45 | 5,630 | 30.00 | 7,500 | — | ||||||||||||||||||||||||||||||||
| November 2020 | July 1 - September 30, 2020 | 0.45 | 5,630 | 15.00 | 3,750 | 3,750 | ||||||||||||||||||||||||||||||||
| 2019 | ||||||||||||||||||||||||||||||||||||||
| February 2019 | October 1 - December 31, 2018 | $ | 0.45 | $ | 5,625 | $ | 30.00 | $ | 7,500 | — | ||||||||||||||||||||||||||||
| May 2019 | January 1 - March 31, 2019 | 0.45 | 5,630 | 30.00 | 7,500 | — | ||||||||||||||||||||||||||||||||
May 2019 (3) | Special Distribution | 0.85 | 10,635 | — | — | — | ||||||||||||||||||||||||||||||||
| August 2019 | April 1 - June 30, 2019 | 0.45 | 5,630 | 30.00 | 7,500 | — | ||||||||||||||||||||||||||||||||
| November 2019 | July 1 - September 30, 2019 | 0.45 | 5,630 | 30.00 | 7,500 | — | ||||||||||||||||||||||||||||||||
Cash Distributions | Paid-in-kind Distributions | |||||||||||||||||||||
Common Units | Preferred Units | |||||||||||||||||||||
Total | Total | Total | ||||||||||||||||||||
Distribution | Distribution (1) | Distribution | Distribution | Distribution | ||||||||||||||||||
Date Paid | Period Covered by Distribution | per Unit | (In thousands) | per Unit | (In thousands) | (In units) | ||||||||||||||||
2023 | ||||||||||||||||||||||
February | October 1 - December 31, 2022 | $ | 0.75 | $ | 9,571 | $ | 30.00 | $ | 7,500 | — | ||||||||||||
February (2) | January 1 - February 8, 2023 | — | — | 12.33 | 586 | — | ||||||||||||||||
March (3) | Special Distribution | 2.43 | 31,329 | — | — | — | ||||||||||||||||
May | January 1 - March 31, 2023 | 0.75 | 9,669 | 30.00 | 6,075 | — | ||||||||||||||||
May (4) | April 1 - May 5, 2023 | — | — | 11.33 | 406 | — | ||||||||||||||||
June (5) | April 1 - June 2, 2023 | — | — | 20.33 | 915 | — | ||||||||||||||||
August | April 1 - June 30, 2023 | 0.75 | 9,669 | 30.00 | 3,650 | — | ||||||||||||||||
August (6) | June 30 - August 8, 2023 | — | — | 12.33 | 432 | — | ||||||||||||||||
September (7) | June 30 - September 12, 2023 | — | — | 23.67 | 355 | — | ||||||||||||||||
November | July 1 - September 30, 2023 | 0.75 | 9,670 | 30.00 | 2,150 | — | ||||||||||||||||
2022 | ||||||||||||||||||||||
February | October 1 - December 31, 2021 | $ | 0.45 | $ | 5,672 | $ | 30.00 | $ | 7,500 | — | ||||||||||||
February (8) | January 1 - February 8, 2022 | — | — | 13.35 | 258 | — | ||||||||||||||||
May | January 1 - March 31, 2022 | 0.75 | 9,570 | 30.00 | 7,500 | — | ||||||||||||||||
August | April 1 - June 30, 2022 | 0.75 | 9,571 | 30.00 | 7,500 | — | ||||||||||||||||
November | July 1 - September 30, 2022 | 0.75 | 9,571 | 30.00 | 7,500 | — | ||||||||||||||||
2021 | ||||||||||||||||||||||
February | October 1 - December 31, 2020 | $ | 0.45 | $ | 5,630 | $ | 15.00 | $ | 3,806 | 3,806 | ||||||||||||
May | January 1 - March 31, 2021 | 0.45 | 5,672 | 15.00 | 3,864 | 3,864 | ||||||||||||||||
August | April 1 - June 30, 2021 | 0.45 | 5,671 | 15.00 | 3,921 | 3,921 | ||||||||||||||||
November | July 1 - September 30, 2021 | 0.45 | 5,672 | 15.00 | 3,980 | 3,980 | ||||||||||||||||
| (1) | Totals include the amount paid to NRP's general partner in accordance with the general partner's 2% general partner interest. | |||||||||||||
(2) | Relates to accrued distribution paid upon the redemption of 47,499 preferred units in February 2023. | |||||||||||||
(3) | Special distribution was made to help cover unitholder tax liabilities associated with owning NRP's common units during 2022. | |||||||||||||
(4) | Relates to accrued distribution paid upon the redemption of 35,834 preferred units in May 2023. | |||||||||||||
(5) | Relates to accrued distribution paid upon the redemption of 45,000 preferred units in June 2023. | |||||||||||||
(6) | Relates to accrued distribution paid upon the redemption of 35,000 preferred units in August 2023. | |||||||||||||
(7) | Relates to accrued distribution paid upon the redemption of 15,001 preferred units in September 2023. | |||||||||||||
(8) | Relates to accrued distribution paid upon the redemption of 19,321 preferred units paid-in-kind in February 2022. |
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Basic net income (loss) per common unit is computed by dividing net income, (loss), after considering income attributable to preferred unitholders, the difference between the fair value of the consideration paid upon redemption and the carrying value of the preferred units, and the general partner’s general partner interest, by the weighted average number of common units outstanding. Diluted net income (loss) per common unit includes the effect of NRP's preferred units, warrants, and unvested unit-based awards if the inclusion of these items is dilutive.
The dilutive effect of the preferred units is calculated using the if-converted method. Under the if-converted method, the preferred units are assumed to be converted at the beginning of the period, and the resulting common units are included in the denominator of the diluted net income (loss) per unit calculation for the period being presented. Distributions declared in the period and undeclared distributions on the preferred units that accumulated during the period are added back to the numerator
The dilutive effect of the warrants is calculated using the treasury stock method, which assumes that the proceeds from the exercise of these instruments are used to purchase common units at the average market price for the period. The calculation of diluted net income per common unit for the year ended December 31, 20212023 includes the net settlement of warrants to purchase 0.75 million1,540,000 common units with a strike price of $34.00. The calculation of diluted net income per common unit for the year ended December 31, 2022 includes the net settlement of warrants to purchase 752,500 common units with a strike price of $22.81 and the net settlement of warrants to purchase 2,250,000 common units with a strike price of $34.00. The calculation of diluted net income per common unit for the year ended December 31, 2021 includes the net settlement of warrants to purchase 752,500 common units with a strike price of $22.81 but does not include the net settlement of warrants to purchase 2.25 million2,250,000 common units with a strike price of $34.00 because the impact would have been anti-dilutive. The calculation of diluted net loss per common unit for the years ended December 31, 2020 and 2019 does not include the net settlement of warrants to purchase 1.75 million common units with a strike price of $22.81 or the net settlement of warrants to purchase 2.25 million common units with a strike price of $34.00 because the impact would have been anti-dilutive.
The following tables reconciletable reconciles the numerators and denominators of the basic and diluted net income (loss) per common unit computations and calculates basic and diluted net income (loss) per common unit:
For the Year Ended December 31, | ||||||||||||
(In thousands, except per unit data) | 2023 | 2022 | 2021 | |||||||||
Basic net income per common unit | ||||||||||||
Net income attributable to common unitholders | $ | 196,771 | $ | 233,722 | $ | 75,747 | ||||||
Weighted average common units—basic | 12,619 | 12,484 | 12,337 | |||||||||
Basic net income per common unit | $ | 15.59 | $ | 18.72 | $ | 6.14 | ||||||
Diluted net income per common unit | ||||||||||||
Weighted average common units—basic | 12,619 | 12,484 | 12,337 | |||||||||
Plus: dilutive effect of preferred units | 2,059 | 6,176 | 9,604 | |||||||||
Plus: dilutive effect of warrants | 1,202 | 783 | 74 | |||||||||
Plus: dilutive effect of unvested unit-based awards | 216 | 210 | 178 | |||||||||
Weighted average common units—diluted | 16,096 | 19,653 | 22,193 | |||||||||
Net income | $ | 278,435 | $ | 268,492 | $ | 108,902 | ||||||
Less: income attributable to preferred unitholders | (2,694 | ) | — | — | ||||||||
Less: redemption of preferred units | (60,929 | ) | — | — | ||||||||
Diluted net income attributable to common unitholders and the general partner | $ | 214,812 | $ | 268,492 | $ | 108,902 | ||||||
Less: diluted net income attributable to the general partner | (4,296 | ) | (5,370 | ) | (2,178 | ) | ||||||
Diluted net income attributable to common unitholders | $ | 210,516 | $ | 263,122 | $ | 106,724 | ||||||
Diluted net income per common unit | $ | 13.08 | $ | 13.39 | $ | 4.81 | ||||||
| For the Year Ended December 31, | ||||||||||||||||||||
| (In thousands, except per unit data) | 2021 | 2020 | 2019 | |||||||||||||||||
| Allocation of net income (loss) | ||||||||||||||||||||
| Net income (loss) from continuing operations | $ | 108,902 | $ | (84,819) | $ | (25,414) | ||||||||||||||
| Less: income attributable to preferred unitholders | (31,609) | (30,225) | (30,000) | |||||||||||||||||
| Net income (loss) from continuing operations attributable to common unitholders and the general partner | $ | 77,293 | $ | (115,044) | $ | (55,414) | ||||||||||||||
| Add (less): net loss (income) from continuing operations attributable to the general partner | (1,546) | 2,301 | 1,108 | |||||||||||||||||
| Net income (loss) from continuing operations attributable to common unitholders | $ | 75,747 | $ | (112,743) | $ | (54,306) | ||||||||||||||
| Net income from discontinued operations | $ | — | $ | — | $ | 956 | ||||||||||||||
| Less: net income from discontinued operations attributable to the general partner | — | — | (19) | |||||||||||||||||
| Net income from discontinued operations attributable to common unitholders | $ | — | $ | — | $ | 937 | ||||||||||||||
| Net income (loss) | $ | 108,902 | $ | (84,819) | $ | (24,458) | ||||||||||||||
| Less: income attributable to preferred unitholders | (31,609) | (30,225) | (30,000) | |||||||||||||||||
| Net income (loss) attributable to common unitholders and the general partner | $ | 77,293 | $ | (115,044) | $ | (54,458) | ||||||||||||||
| Add (less): net loss (income) attributable to the general partner | (1,546) | 2,301 | 1,089 | |||||||||||||||||
| Net income (loss) attributable to common unitholders | $ | 75,747 | $ | (112,743) | $ | (53,369) | ||||||||||||||
| Basic income (loss) per common unit | ||||||||||||||||||||
| Weighted average common units—basic | 12,337 | 12,261 | 12,260 | |||||||||||||||||
| Basic net income (loss) from continuing operations per common unit | $ | 6.14 | $ | (9.20) | $ | (4.43) | ||||||||||||||
| Basic net income from discontinued operations per common unit | $ | — | $ | — | $ | 0.08 | ||||||||||||||
| Basic net income (loss) per common unit | $ | 6.14 | $ | (9.20) | $ | (4.35) | ||||||||||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
| For the Year Ended December 31, | ||||||||||||||||||||
| (In thousands, except per unit data) | 2021 | 2020 | 2019 | |||||||||||||||||
| Diluted income (loss) per common unit | ||||||||||||||||||||
| Weighted average common units—basic | 12,337 | 12,261 | 12,260 | |||||||||||||||||
| Plus: dilutive effect of preferred units | 9,604 | — | — | |||||||||||||||||
| Plus: dilutive effect of warrants | 74 | — | — | |||||||||||||||||
| Plus: dilutive effect of unvested unit-based awards | 178 | — | — | |||||||||||||||||
| Weighted average common units—diluted | 22,193 | 12,261 | 12,260 | |||||||||||||||||
| Net income (loss) from continuing operations | $ | 108,902 | $ | (84,819) | $ | (25,414) | ||||||||||||||
| Less: income attributable to preferred unitholders | — | (30,225) | (30,000) | |||||||||||||||||
| Diluted net income (loss) from continuing operations attributable to common unitholders and the general partner | $ | 108,902 | $ | (115,044) | $ | (55,414) | ||||||||||||||
| Add (less): net loss (income) from continuing operations attributable to the general partner | (2,178) | 2,301 | 1,108 | |||||||||||||||||
| Diluted net income (loss) from continuing operations attributable to common unitholders | $ | 106,724 | $ | (112,743) | $ | (54,306) | ||||||||||||||
| Diluted net income from discontinued operations attributable to common unitholders | $ | — | $ | — | $ | 937 | ||||||||||||||
| Net income (loss) | $ | 108,902 | $ | (84,819) | $ | (24,458) | ||||||||||||||
| Less: income attributable to preferred unitholders | — | (30,225) | (30,000) | |||||||||||||||||
| Diluted net income (loss) attributable to common unitholders and the general partner | $ | 108,902 | $ | (115,044) | $ | (54,458) | ||||||||||||||
| Add (less): diluted net loss (income) attributable to the general partner | (2,178) | 2,301 | 1,089 | |||||||||||||||||
| Diluted net income (loss) attributable to common unitholders | $ | 106,724 | $ | (112,743) | $ | (53,369) | ||||||||||||||
| Diluted net income (loss) from continuing operations per common unit | $ | 4.81 | $ | (9.20) | $ | (4.43) | ||||||||||||||
| Diluted net income from discontinued operations per common unit | $ | — | $ | — | $ | 0.08 | ||||||||||||||
| Diluted net income (loss) per common unit | $ | 4.81 | $ | (9.20) | $ | (4.35) | ||||||||||||||
The Partnership's segments are strategic business units that offer distinct products and services to different customers in different geographies within the U.S. and that are managed accordingly. NRP has the following 2two operating segments:
Mineral Rights (formerly named Coal Royalty and Other segment)
Soda Ash
—consists of the Partnership's 49% non-controlling equity interest in Sisecam Wyoming, a trona ore mining operation and soda ash refinery in the Green River Basin of Wyoming. Sisecam Wyoming mines trona and processes it into soda ash that is sold both domestically and internationally into the glass and chemicals industries.Direct segment costs and certain other costs incurred at the corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments accordingly. These allocated costs generally include salaries and benefits, insurance, property taxes, legal, royalty, information technology and shared facilities services and are included in operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest and financing, corporate headquarters and overhead, centralized treasury, legal and accounting and other corporate-level activity not specifically allocated to a segment and are included in general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
The following table summarizes certain financial information for each of the Partnership's business segments:
Operating Segments | ||||||||||||||||
(In thousands) | Mineral Rights | Soda Ash | Corporate and Financing | Total | ||||||||||||
For the Year Ended December 31, 2023 | ||||||||||||||||
Revenues | $ | 293,656 | $ | 73,397 | $ | — | $ | 367,053 | ||||||||
Gain on asset sales and disposals | 2,956 | — | — | 2,956 | ||||||||||||
Operating and maintenance expenses | 32,058 | 257 | — | 32,315 | ||||||||||||
Depreciation, depletion and amortization | 18,471 | — | 18 | 18,489 | ||||||||||||
General and administrative expenses | — | — | 26,111 | 26,111 | ||||||||||||
Asset impairments | 556 | — | — | 556 | ||||||||||||
Other expenses, net | — | — | 14,103 | 14,103 | ||||||||||||
Net income (loss) | 245,527 | 73,140 | (40,232 | ) | 278,435 | |||||||||||
As of December 31, 2023 | ||||||||||||||||
Total assets | $ | 516,844 | $ | 276,549 | $ | 4,483 | $ | 797,876 | ||||||||
For the Year Ended December 31, 2022 | ||||||||||||||||
Revenues | $ | 328,085 | $ | 59,795 | $ | — | $ | 387,880 | ||||||||
Gain on asset sales and disposals | 1,082 | — | — | 1,082 | ||||||||||||
Operating and maintenance expenses | 34,743 | 160 | — | 34,903 | ||||||||||||
Depreciation, depletion and amortization | 22,519 | — | — | 22,519 | ||||||||||||
General and administrative expenses | — | — | 21,852 | 21,852 | ||||||||||||
Asset impairments | 4,457 | — | — | 4,457 | ||||||||||||
Other expenses, net | — | — | 36,739 | 36,739 | ||||||||||||
Net income (loss) | 267,448 | 59,635 | (58,591 | ) | 268,492 | |||||||||||
As of December 31, 2022 | ||||||||||||||||
Total assets | $ | 566,615 | $ | 306,470 | $ | 4,046 | $ | 877,131 | ||||||||
For the Year Ended December 31, 2021 | ||||||||||||||||
Revenues | $ | 194,248 | $ | 21,871 | $ | — | $ | 216,119 | ||||||||
Gain on asset sales and disposals | 245 | — | — | 245 | ||||||||||||
Operating and maintenance expenses | 26,880 | 169 | — | 27,049 | ||||||||||||
Depreciation, depletion and amortization | 19,075 | — | — | 19,075 | ||||||||||||
General and administrative expenses | — | — | 17,360 | 17,360 | ||||||||||||
Asset impairments | 5,102 | — | — | 5,102 | ||||||||||||
Other expenses, net | 24 | — | 38,852 | 38,876 | ||||||||||||
Net income (loss) | 143,412 | 21,702 | (56,212 | ) | 108,902 | |||||||||||
| Operating Segments | ||||||||||||||||||||||||||
| (In thousands) | Mineral Rights | Soda Ash | Corporate and Financing | Total | ||||||||||||||||||||||
| For the Year Ended December 31, 2021 | ||||||||||||||||||||||||||
| Revenues | $ | 194,248 | $ | 21,871 | $ | — | $ | 216,119 | ||||||||||||||||||
| Gain on asset sales and disposals | 245 | — | — | 245 | ||||||||||||||||||||||
| Operating and maintenance expenses | 26,880 | 169 | — | 27,049 | ||||||||||||||||||||||
| Depreciation, depletion and amortization | 19,075 | — | — | 19,075 | ||||||||||||||||||||||
| General and administrative expenses | — | — | 17,360 | 17,360 | ||||||||||||||||||||||
| Asset impairments | 5,102 | — | — | 5,102 | ||||||||||||||||||||||
| Other expenses, net | 24 | — | 38,852 | 38,876 | ||||||||||||||||||||||
| Net income (loss) from continuing operations | 143,412 | 21,702 | (56,212) | 108,902 | ||||||||||||||||||||||
| As of December 31, 2021 | ||||||||||||||||||||||||||
| Total assets | $ | 675,579 | $ | 276,004 | $ | 2,240 | $ | 953,823 | ||||||||||||||||||
| For the Year Ended December 31, 2020 | ||||||||||||||||||||||||||
| Revenues | $ | 129,011 | $ | 10,728 | $ | — | $ | 139,739 | ||||||||||||||||||
| Gain on asset sales and disposals | 581 | — | — | 581 | ||||||||||||||||||||||
| Operating and maintenance expenses | 24,610 | 185 | — | 24,795 | ||||||||||||||||||||||
| Depreciation, depletion and amortization | 9,198 | — | — | 9,198 | ||||||||||||||||||||||
| General and administrative expenses | — | — | 14,293 | 14,293 | ||||||||||||||||||||||
| Asset impairments | 135,885 | — | — | 135,885 | ||||||||||||||||||||||
| Other expenses, net | 79 | — | 40,889 | 40,968 | ||||||||||||||||||||||
| Net income (loss) from continuing operations | (40,180) | 10,543 | (55,182) | (84,819) | ||||||||||||||||||||||
| As of December 31, 2020 | ||||||||||||||||||||||||||
| Total assets | $ | 656,505 | $ | 262,514 | $ | 2,858 | $ | 921,877 | ||||||||||||||||||
| For the Year Ended December 31, 2019 | ||||||||||||||||||||||||||
| Revenues | $ | 210,348 | $ | 47,089 | $ | — | $ | 257,437 | ||||||||||||||||||
| Gain on asset sales and disposals | 6,498 | — | — | 6,498 | ||||||||||||||||||||||
| Operating and maintenance expenses | 32,489 | 249 | — | 32,738 | ||||||||||||||||||||||
| Depreciation, depletion and amortization | 14,932 | — | — | 14,932 | ||||||||||||||||||||||
| General and administrative expenses | — | — | 16,730 | 16,730 | ||||||||||||||||||||||
| Asset impairments | 148,214 | — | — | 148,214 | ||||||||||||||||||||||
| Other expenses, net | — | — | 76,735 | 76,735 | ||||||||||||||||||||||
| Net income (loss) from continuing operations | 21,211 | 46,840 | (93,465) | (25,414) | ||||||||||||||||||||||
| Income from discontinued operations | — | — | — | 956 | ||||||||||||||||||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
8.Equity Investment
The Partnership accounts for its 49% investment in Sisecam Wyoming using the equity method of accounting. Activity related to this investment is as follows:
| For the Year Ended December 31, | |||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Balance at beginning of period | $ | 262,514 | $ | 263,080 | $ | 247,051 | |||||||||||
Income allocation to NRP’s equity interests (1) | 26,979 | 15,205 | 52,016 | ||||||||||||||
| Amortization of basis difference | (5,108) | (4,477) | (4,927) | ||||||||||||||
| Other comprehensive income | 2,889 | 2,916 | 790 | ||||||||||||||
| Distribution | (11,270) | (14,210) | (31,850) | ||||||||||||||
| Balance at end of period | $ | 276,004 | $ | 262,514 | $ | 263,080 | |||||||||||
For the Year Ended December 31, | ||||||||||||
(In thousands) | 2023 | 2022 | 2021 | |||||||||
Balance at beginning of period | $ | 306,470 | $ | 276,004 | $ | 262,514 | ||||||
Income allocation to NRP’s equity interests (1) | 78,179 | 64,712 | 26,979 | |||||||||
Amortization of basis difference | (4,783 | ) | (4,917 | ) | (5,108 | ) | ||||||
Other comprehensive income (loss) | (21,839 | ) | 15,506 | 2,889 | ||||||||
Distributions | (81,478 | ) | (44,835 | ) | (11,270 | ) | ||||||
Balance at end of period | $ | 276,549 | $ | 306,470 | $ | 276,004 | ||||||
(1) | Amounts reclassified into income out of accumulated other comprehensive loss were $(17.9) million, $(6.8) million and $0.0 million for the year ended December 31, 2023, 2022 and 2021, respectively. | |||||||||||||
The difference between the amount at which the investment in Sisecam Wyoming is carried and the amount of underly
The following table represents summarized financial information for Sisecam Wyoming as derived from their respective financial statements for the years ended December 31, 2021, 2020,2023, 2022, and 2019:
| For the Year Ended December 31, | |||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Net sales | $ | 540,139 | $ | 392,231 | $ | 522,843 | |||||||||||
| Gross profit | 80,550 | 54,838 | 131,712 | ||||||||||||||
| Net income | 55,059 | 31,030 | 106,155 | ||||||||||||||
For the Year Ended December 31, | ||||||||||||
(In thousands) | 2023 | 2022 | 2021 | |||||||||
Net sales | $ | 773,590 | $ | 720,120 | $ | 540,139 | ||||||
Gross profit | 187,929 | 162,575 | 80,550 | |||||||||
Net income | 159,549 | 132,065 | 55,059 | |||||||||
The financial position of Sisecam Wyoming is summarized as follows:
December 31, | ||||||||
(In thousands) | 2023 | 2022 | ||||||
Current assets | $ | 253,754 | $ | 340,437 | ||||
Noncurrent assets | 284,131 | 292,915 | ||||||
Current liabilities | 91,853 | 111,258 | ||||||
Noncurrent liabilities | 119,533 | 144,290 | ||||||
| December 31, | |||||||||||
| (In thousands) | 2021 | 2020 | |||||||||
| Current assets | $ | 206,315 | $ | 164,720 | |||||||
| Noncurrent assets | 297,210 | 294,008 | |||||||||
| Current liabilities | 73,181 | 55,313 | |||||||||
| Noncurrent liabilities | 124,749 | 135,776 | |||||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
The Partnership’s mineral rights consist of the following:
| December 31, | |||||||||||||||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||||||||||||||
| (In thousands) | Carrying Value | Accumulated Depletion | Net Book Value | Carrying Value | Accumulated Depletion | Net Book Value | |||||||||||||||||||||||||||||
| Coal properties | $ | 670,650 | $ | (253,503) | $ | 417,147 | $ | 785,623 | $ | (346,773) | $ | 438,850 | |||||||||||||||||||||||
| Aggregates properties | 8,747 | (2,975) | 5,772 | 9,039 | (2,819) | 6,220 | |||||||||||||||||||||||||||||
| Oil and gas royalty properties | 12,354 | (9,115) | 3,239 | 12,354 | (8,593) | 3,761 | |||||||||||||||||||||||||||||
| Other | 13,151 | (1,612) | 11,539 | 13,154 | (1,612) | 11,542 | |||||||||||||||||||||||||||||
| Total mineral rights, net | $ | 704,902 | $ | (267,205) | $ | 437,697 | $ | 820,170 | $ | (359,797) | $ | 460,373 | |||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2023 | 2022 | |||||||||||||||||||||||
(In thousands) | Carrying Value | Accumulated Depletion | Net Book Value | Carrying Value | Accumulated Depletion | Net Book Value | ||||||||||||||||||
Coal properties | $ | 661,256 | $ | (285,470 | ) | $ | 375,786 | $ | 661,812 | $ | (269,037 | ) | $ | 392,775 | ||||||||||
Aggregates properties | 8,655 | (3,761 | ) | 4,894 | 8,655 | (3,410 | ) | 5,245 | ||||||||||||||||
Oil and gas royalty properties | 12,354 | (10,082 | ) | 2,272 | 12,354 | (9,600 | ) | 2,754 | ||||||||||||||||
Other | 13,143 | (1,612 | ) | 11,531 | 13,150 | (1,612 | ) | 11,538 | ||||||||||||||||
Total mineral rights, net | $ | 695,408 | $ | (300,925 | ) | $ | 394,483 | $ | 695,971 | $ | (283,659 | ) | $ | 412,312 | ||||||||||
Depletion expense related to the Partnership’s mineral rights is included in depreciation, depletion and amortization on its Consolidated Statements of Comprehensive Income (Loss) and totaled $17.6$17.3 million, $8.8$20.9 million and $12.1$17.6 million for the year ended December 31, 2021, 20202023, 2022 and 2019,2021, respectively.
Impairment of Mineral Rights
During the years ended December 31, 2021, 20202023, 2022 and 2019,2021, the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense included in asset impairments on the Consolidated Statements of Comprehensive Income (Loss) as follows:
| For the Year Ended December 31, | |||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | ||||||||||||||
Coal properties (1) | $ | 5,015 | $ | 114,302 | $ | 125,806 | |||||||||||
Aggregates properties (2) | 87 | 21,583 | 103 | ||||||||||||||
| Total | $ | 5,102 | $ | 135,885 | $ | 125,909 | |||||||||||
For the Year Ended December 31, | ||||||||||||
(In thousands) | 2023 | 2022 | 2021 | |||||||||
Coal properties (1) | $ | 556 | $ | 4,365 | $ | 5,015 | ||||||
Aggregates properties (2) | — | 92 | 87 | |||||||||
Total | $ | 556 | $ | 4,457 | $ | 5,102 | ||||||
(1) | The Partnership recorded $0.6 million of impairment expense during the year ended December 31, 2023. The Partnership recorded $4.4 million of impairment expense during the year ended December 31, 2022 primarily related to assets whose undiscounted future net cash flows were less than their net book values. Of this amount, $2.6 million of impairment expense related to an asset with $4.3 million of net book value, resulting in a fair value of $1.7 million at December 31, 2022. The fair value of the impaired asset at December 31, 2022 was calculated using a discount rate of 15%. The Partnership recorded $5.0 million of impairment expense during the year ended December 31, 2021 primarily related to the full impairment of an asset resulting from a lease termination. NRP compared the net book value of its coal properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of the net book value over fair value. A discounted cash flow model was used to estimate the level 3 fair value. Significant inputs used to determine fair value include estimates of future cash flows from coal sales and minimum payments, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. |
(2) | The Partnership recorded $0.1 million of aggregates royalty property impairments during the years ended December 31, 2022 and 2021. NRP compared the net book value of its aggregates properties to estimated undiscounted future net cash flows. If the net book value exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of the net book value over fair value. A discounted cash flow model was used to estimate the level 3 fair value. Significant inputs used to determine fair value include estimates of future cash flows from aggregates sales and minimum payments, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. | |||||||||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
10.Intangible Assets, Net
The Partnership's intangible assets consist of above-market coal royalty and related transportation contracts with subsidiaries of Foresight Energy Resources LLC ("Foresight") pursuant to which the Partnership receives royalty payments for coal sales and throughput fees for the transportation and processing of coal. The Partnership's intangible assets included on its Consolidated Balance Sheets are as follows:
| December 31, | |||||||||||
| (In thousands) | 2021 | 2020 | |||||||||
| Intangible assets at cost | $ | 51,353 | $ | 53,878 | |||||||
| Less: accumulated amortization | (35,223) | (36,419) | |||||||||
| Total intangible assets, net | $ | 16,130 | $ | 17,459 | |||||||
December 31, | ||||||||
(In thousands) | 2023 | 2022 | ||||||
Intangible assets at cost | $ | 51,353 | $ | 51,353 | ||||
Less: accumulated amortization | (37,671 | ) | (36,640 | ) | ||||
Total intangible assets, net | $ | 13,682 | $ | 14,713 | ||||
Amortization expense included in depreciation, depletion and amortization on the Partnership's Consolidated Statements of Comprehensive Income (Loss) was $1.3$1.0 million, $0.2 $1.4 million and $2.5$1.3 million for the year ended December 31, 2021, 20202023, 2022 and 2019,2021, respectively.
The estimates of amortization expense for the years ended December 31, as indicated below, are based on current lessee mining plans and are subject to revision as those plans change in future periods.
(In thousands) | Estimated Amortization Expense | |||
2024 | $ | 884 | ||
2025 | 813 | |||
2026 | 753 | |||
2027 | 720 | |||
2028 | 480 | |||
| (In thousands) | Estimated Amortization Expense | |||||||
| 2022 | $ | 1,127 | ||||||
| 2023 | 1,041 | |||||||
| 2024 | 1,238 | |||||||
| 2025 | 1,202 | |||||||
| 2026 | 1,202 | |||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
The Partnership's debt consists of the following:
| December 31, | |||||||||||
| (In thousands) | 2021 | 2020 | |||||||||
| NRP LP debt: | |||||||||||
| 9.125% senior notes, with semi-annual interest payments in June and December, due June 2025 issued at par ("2025 Senior Notes") | $ | 300,000 | $ | 300,000 | |||||||
| Opco debt: | |||||||||||
| Revolving credit facility | $ | — | $ | — | |||||||
| Senior Notes | |||||||||||
| 5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 | $ | 4,730 | $ | 7,094 | |||||||
| 4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 | 12,008 | 18,013 | |||||||||
| 5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 38,053 | 50,738 | |||||||||
| 8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 12,035 | 16,047 | |||||||||
| 5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 57,104 | 68,524 | |||||||||
| 5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 14,554 | 17,464 | |||||||||
| Total Opco Senior Notes | $ | 138,484 | $ | 177,880 | |||||||
| Total debt at face value | $ | 438,484 | $ | 477,880 | |||||||
| Net unamortized debt issuance costs | (4,939) | (6,381) | |||||||||
| Total debt, net | $ | 433,545 | $ | 471,499 | |||||||
| Less: current portion of long-term debt | (39,102) | (39,055) | |||||||||
| Total long-term debt, net | $ | 394,443 | $ | 432,444 | |||||||
December 31, | ||||||||
(In thousands) | 2023 | 2022 | ||||||
Opco Credit Facility | $ | 95,834 | $ | 70,000 | ||||
Opco Senior Notes | ||||||||
5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 | $ | — | $ | 2,366 | ||||
4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 | — | 6,004 | ||||||
5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 12,685 | 25,368 | ||||||
8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 4,012 | 8,023 | ||||||
5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 34,262 | 45,683 | ||||||
5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 8,732 | 11,643 | ||||||
Total Opco Senior Notes | $ | 59,691 | $ | 99,087 | ||||
Total debt at face value | $ | 155,525 | $ | 169,087 | ||||
Net unamortized debt issuance costs | (467 | ) | (806 | ) | ||||
Total debt, net | $ | 155,058 | $ | 168,281 | ||||
Less: current portion of long-term debt | (30,785 | ) | (39,076 | ) | ||||
Total long-term debt, net | $ | 124,273 | $ | 129,205 | ||||
NRP LP Debt
2025 Senior Notes
In 2022, NRP redeemed all $300 million of its 2025 Senior Notes. Included in loss on extinguishment of debt on the Partnership's Consolidated Statements of Comprehensive Income for the year ended December 31, 2022, are $7.2 million of call premium and fees and the write off of $3.1 million of debt issuance costs. The cash paid for call premiums and fees is included in other items, net under cash used in financing activities on the Consolidated Statements of Cash Flows. The following describes the terms of the 2025 Senior Notes prior to their redemption.
The 2025 Senior Notes were issued under an Indenture dated as of April 29, 2019 (the "2025(the "2025 Indenture"), bearbore interest at 9.125% per year and maturewould have matured on June 30, 2025. Interest iswas payable semi-annually on June 30 and December 30. NRP and NRP Finance havehad the option to redeem the 2025 Senior Notes, in whole or in part, at any time on or after October 30, 2021, at the redemption prices (expressed as percentages of principal amount) of 104.563% for the 12-month12-month period beginning October 30, 2021, 102.281% for the 12-month12-month period beginning October 30, 2022, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the date of redemption. In the event of a change of control, as defined in the 2025 Indenture, the holders of the 2025 Senior Notes may requirehave required us to purchase their 2025 Senior Notes at a purchase price equal to 101% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest, if any. The 2025 Senior Notes were issued at par.
The 2025 Senior Notes arewere the senior unsecured obligations of NRP and NRP Finance.NRP. The 2025 Senior Notes rankranked equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance and senior in right of payment to any of NRP's subordinated debt. The 2025 Senior Notes arewere effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and arewas structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiaries guaranteeguaranteed the 2025 Senior Notes. As of December 31, 2021 and 2020, NRP and NRP Finance were in compliance with the terms of the Indenture relating to their 2025 Senior Notes.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
Opco Debt
All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries, other than BRP LLC and NRP Trona LLC. As of December 31, 2021 2023 and 2020,2022, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.
Opco Credit Facility
In 2019,May 2023, the Partnership entered into the FourthSixth Amendment (the “Fourth Amendment”"Sixth Amendment") to the Opco Credit Facility (the "Opco Credit Facility"). The FourthSixth Amendment extendsextended the term of the Opco Credit Facility until April 2023. August 2027. Lender commitments under the Opco Credit Facility remain at $100.0 million.
Indebtedness under the Opco Credit Facility bears interest, at Opco's option, at:
• | the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) SOFR plus 1%, in each case plus an applicable margin ranging from 2.50% to 3.50%; or |
• | a rate equal to SOFR plus an applicable margin ranging from 3.50% to 4.50%. |
During the yearsyear ended December 31, 2021 and 2020, 2022, the Partnership did not have anyborrowed $70.0 million under the Opco Credit Facility, resulting in $70.0 million in borrowings outstanding and $60.0 million of available borrowing capacity under the Opco Credit Facility as of December 31, 2022. During the year ended December 31, 2023 the Partnership borrowed $248.8 million and repaid $223.0 million, resulting in $95.8 million in borrowings outstanding and $59.2 of available borrowing capacity under the Opco Credit Facility as of December 31, 2023. The weighted average interest rate for the borrowings outstanding under the Opco Credit Facility and had $100.0 million in available borrowing capacity at both for the year ended December 31, 2021 2023 and 2020.2022 were 8.70% and 7.17%, respectively. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty.
The Opco Credit Facility contains financial covenants requiring Opco to maintain:
• | A leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 3.0x; and |
• | an interest coverage ratio of consolidated EBITDDA to consolidated interest expense and consolidated lease expense (in each case as defined in the Opco Credit Facility) of not less than 3.5 to 1.0. |
The Opco Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of liquidity. In addition, Opco is required to use 75% of the net cash proceeds of certain non-ordinary course asset sales to repay the Opco Credit Facility (without any corresponding commitment reduction) and use the remaining 25% of the net cash proceeds to offer to repay its Senior Notes on a pro-rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility also contains customary events of default, including cross-defaults under Opco’s Senior Notes.
The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values o
fIn February 2024, the Partnership exercised its option under the Opco Credit Facility to increase the total aggregate commitment under the Opco Credit Facility twice, initially by $30.0 million from $155.0 million to $185.0 million and subsequently by $15.0 million from $185.0 million to $200.0 million. These increases in the total aggregate commitment were made pursuant to an accordion feature of the Opco Credit Facility. In connection with the initial increase, a new lender joined the lending group with a commitment of $30.0 million. The Opco Credit Facility otherwise continues to operate under its existing terms and conditions in all material respects.
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
Opco Senior Notes
Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of December 31, 2021 2023 and 2020,2022, the Opco Senior Notes had cumulative principal balances of $138.5$59.7 million and $177.9$99.1 million, respectively. Opco made mandatory principal payments on the Opco Senior Notes of $39.4 million $46.2 million and $117.4 million during the yearyears ended December 31, 2021, 20202023, 2022 and 2019, respectively. The payments made during the year ended December 31, 2019 included a $49.3 million pre-payment as a result of the sale of the Partnership's construction aggregates business.
The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to:
• | maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters; |
• | not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and |
• | maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0. |
In addition, the Note Purchase Agreements include a covenant that provides that, in the event NRP OperatingOpco or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the Note Purchase Agreements and the holders of the Notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement.
The 8.92% Opco Senior Notes also provides that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Note Purchase Agreements) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2021.
In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepayment offers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid.
The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes.
Consolidated Principal Payments
The consolidated principal payments due are set forth below:
| NRP LP | Opco | ||||||||||||||||||||||
| (In thousands) | Senior Notes | Senior Notes | Credit Facility | Total | |||||||||||||||||||
| 2022 | $ | — | $ | 39,396 | $ | — | $ | 39,396 | |||||||||||||||
| 2023 | — | 39,396 | — | 39,396 | |||||||||||||||||||
| 2024 | — | 31,028 | — | 31,028 | |||||||||||||||||||
| 2025 | 300,000 | 14,332 | — | 314,332 | |||||||||||||||||||
| 2026 | — | 14,332 | — | 14,332 | |||||||||||||||||||
| Thereafter | — | — | — | — | |||||||||||||||||||
| $ | 300,000 | $ | 138,484 | $ | — | $ | 438,484 | ||||||||||||||||
(In thousands) | Opco Senior Notes | Opco Credit Facility | Total | |||||||||
2024 | $ | 31,028 | $ | — | $ | 31,028 | ||||||
2025 | 14,332 | — | 14,332 | |||||||||
2026 | 14,331 | — | 14,331 | |||||||||
2027 | — | 95,834 | 95,834 | |||||||||
2028 | — | — | — | |||||||||
Thereafter | — | — | — | |||||||||
| $ | 59,691 | $ | 95,834 | $ | 155,525 | |||||||
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
Fair Value of Financial Assets and Liabilities
The Partnership’s financial assets and liabilities consist of cash and cash equivalents, a contract receivable and debt. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents approximate fair value due to their short-term nature. The Partnership uses available market data and valuation methodologies to estimate the fair value of its debt and contract receivable.
The following table shows the carrying value and estimated fair value of the Partnership's debt and contract receivable:
| December 31, | |||||||||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||||||||
| (In thousands) | Fair Value Hierarchy Level | Carrying Value | Estimated Fair Value | Carrying Value | Estimated Fair Value | ||||||||||||||||||||||||
| Debt: | |||||||||||||||||||||||||||||
| NRP 2025 Senior Notes | 1 | $ | 296,236 | $ | 300,000 | $ | 295,160 | $ | 274,500 | ||||||||||||||||||||
Opco Senior Notes (1) | 3 | 137,309 | 138,484 | 176,339 | 162,760 | ||||||||||||||||||||||||
| Opco Credit Facility | 3 | — | — | — | — | ||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
Contract receivable, net (current and long-term) (2) | 3 | $ | 33,612 | $ | 26,010 | $ | 35,313 | $ | 27,025 | ||||||||||||||||||||
December 31, | ||||||||||||||||||||
2023 | 2022 | |||||||||||||||||||
Carrying | Estimated | Carrying | Estimated | |||||||||||||||||
(In thousands) | Fair Value Hierarchy Level | Value | Fair Value | Value | Fair Value | |||||||||||||||
Debt: | ||||||||||||||||||||
Opco Senior Notes (1) | 3 | $ | 59,224 | $ | 56,533 | $ | 98,281 | $ | 96,060 | |||||||||||
Opco Credit Facility (2) | 3 | 95,834 | 95,384 | 70,000 | 70,000 | |||||||||||||||
Assets: | ||||||||||||||||||||
Contract receivable, net (current and long-term) (3) | 3 | $ | 28,946 | $ | 24,492 | $ | 31,371 | $ | 24,833 | |||||||||||
(1) | The fair value of the Opco Senior Notes was estimated by management utilizing the present value replacement method incorporating the interest rate of the Opco Credit Facility. |
(2) | The fair value of the Opco Credit Facility approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. |
(3) | The fair value of the Partnership's contract receivable was determined based on the present value of future cash flow projections related to the underlying asset at a discount rate of 15% at December 31, 2023 and 2022. | |||||||||||||
NRP has embedded derivatives in the preferred units related to certain conversion options, redemption features and the change of control provision that are accounted for separately from the preferred units as assets and liabilities at fair value on the Partnership's Consolidated Balance Sheets. Level 3 valuation of the embedded derivatives are based on numerous factors including the likelihood of the event occurring. The embedded derivatives are revalued quarterly and changes in their fair value would be recorded in other expenses, net on the Partnership's Consolidated Statements of Comprehensive Income (Loss).Income. The embedded derivatives had zero value as of December 31, 2021 2023 and 2020.
Fair Value of Non-Financial Assets
The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregates properties at fair value on a nonrecurring basis. Refer to
Note 9. Mineral Rights, Net for additional disclosures related to the fair value associated with the impaired assets.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its management of NRP. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, provide their services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. These QMC and WPPLP employee management service costs are presented as operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).Income. NRP also reimburses overhead costs incurred by its affiliates, including Quintana Infrastructure Development ("QID"), to manage the Partnership's business. These overhead costs include certain rent, information technology, administration of employee benefits and other corporate services incurred by or on behalf of the Partnership’s general partner and its affiliates and are presented as operating and maintenance expenses and general and administrative expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).
Direct general and administrative expenses charged to the Partnership by QMC, WPPLP and QID are included on the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows:
| For the Year Ended December 31, | |||||||||||||||||
| (In thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Operating and maintenance expenses | $ | 6,543 | $ | 6,559 | $ | 6,656 | |||||||||||
| General and administrative expenses | 4,611 | 4,611 | 4,946 | ||||||||||||||
For the Year Ended December 31, | ||||||||||||
(In thousands) | 2023 | 2022 | 2021 | |||||||||
Operating and maintenance expenses | $ | 6,747 | $ | 6,694 | $ | 6,543 | ||||||
General and administrative expenses | 5,408 | 4,864 | 4,611 | |||||||||
The Partnership had accounts payable to QMC of $0.4 million on its Consolidated Balance Sheets as of at both December 31, 2021 2023 and 20202022 and $0.9$0.2 million and $0.3$1.0 million of accounts payable to WPPLP as of at December 31, 2021 2023 and 2020,2022, respectively.
As a result of its office lease with WPPLP, the Partnership had a right-of-use asset and lease liability of $3.5 million included in other long-term assets, net and other non-current liabilities, respectively, on its Consolidated Balance Sheets at both December 31, 2023 and 2022.
During the years ended December 31, 2021, 20202023, 2022 and 2019,2021, the Partnership recognized $3.3$5.1 million, $0.4$8.5 million and $4.0$3.3 million in operating and maintenance expenses, respectively, on its Consolidated Statements of Comprehensive Income (Loss) related to an overriding royalty agreement with WPPLP. At December 31, 2021 and 2020, the Partnership ha
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
Revenues from customers that exceeded 10 percent of total revenues for any of the periods presented below are as follows:
| For the Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||||||||
| (In thousands) | Revenues | Percent | Revenues | Percent | Revenues | Percent | ||||||||||||||||||||||||||||||||
Foresight (1) (2) | $ | 37,366 | 17 | % | $ | 35,704 | 26 | % | $ | 58,923 | 23 | % | ||||||||||||||||||||||||||
Alpha Metallurgical Resources, Inc. (1) | 49,440 | 23 | % | 33,227 | 24 | % | 40,743 | 16 | % | |||||||||||||||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||||||||||
2023 | 2022 | 2021 | ||||||||||||||||||||||
(In thousands) | Revenues | Percent | Revenues | Percent | Revenues | Percent | ||||||||||||||||||
Alpha Metallurgical Resources, Inc. (1) | $ | 86,118 | 23 | % | $ | 102,352 | 26 | % | $ | 49,440 | 23 | % | ||||||||||||
Foresight (1) (2) | 60,495 | 16 | % | 65,597 | 17 | % | 37,366 | 17 | % | |||||||||||||||
(1) | Revenues from Alpha Metallurgical Resources, Inc. and Foresight are included within the Partnership's Mineral Rights segment. |
(2) | Revenues from Foresight in 2021 were fixed as a result of the lease amendment the Partnership entered into with Foresight pursuant to which Foresight agreed to pay NRP fixed cash payments to satisfy all obligations arising out of the existing various coal mining leases and transportation infrastructure fee agreements between the Partnership and Foresight. Revenues from Foresight in 2022 and 2023 represent traditional royalty and minimum payments. | |||||||||||||
15.Commitments and Contingencies
Legal
NRP is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these ordinary course matters will not have a material effect on the Partnership’s financial position, liquidity or operations.
Environmental Compliance
The operations the Partnership’s lessees conduct on its properties, as well as the industrial minerals, aggregates and oil and gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. See "
Items 1. and 2. Business and Properties—Regulation and Environmental Matters." As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership makes regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. The Partnership believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply with environmental laws and regulations will have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31,As a former owner of the working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities, including environmental liabilities, arising from uninsured and underinsured events during the period it was an owner.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
2017 Long-Term Incentive Plan
In December 2017, the 2017 Long-Term Incentive Plan (the “2017“2017 LTIP”) was approved and it became effective in January 2018. The 2017 LTIP authorizes 800,000a total of 1,600,000 common units that are available for delivery by the Partnership pursuant to awards under the plan. The initial number of common units authorized for issuance pursuant to awards under the plan was 800,000 and in March 2022, an additional 800,000 units were authorized for issuance. The term is 10 years from the date of approval of the Board of Directors or, if earlier, the date the 2017 LTIP is terminated by the Board of Directors or the committee appointed by the Board of Directors to administer the 2017 LTIP, or the date all available common units available have been delivered. Common units delivered pursuant to the 2017 LTIP will consist, in whole or part, of (i) common units acquired in the open market, (ii) common units acquired from the Partnership (including newly issued units), any of our affiliates or any other person or (iii) any combination of the foregoing.
Employees, consultants and non-employee directors of the Partnership, the General Partner,general partner, GP LLC and their affiliates are generally eligible to receive awards under the 2017 LTIP. The 2017 LTIP provides for the issuance of a variety of equity-based grants, including grants of (i) options, (ii) unit appreciation rights, (iii) restricted units, (iv) phantom units, (v) cash awards, (vi) performance awards, (vii) distribution equivalent rights, and (viii) other unit-based awards. The plan is administered by the Compensation, Nominating and Governance Committee ("CNG Committee") of the Board of Directors, which determines the terms and conditions of awards granted under the 2017 LTIP. The Partnership recognizes forfeitures for any awards issued under this plan as they occur.
Unit-Based Awards
Unit-based awards under the 2017 LTIP are generally issued to certain employees and non-employee directors of the Partnership. Awards granted to employees either vest 3 years following the grant date or vest ratably over the 3 year period following the grant date. Awards granted to non-employee directors vest over a 1 year period. Directors are given the option to take immediate issuance of the vested awards or defer such issuance until a later date. Upon deferral of issuance, such units will continue to accumulate distribution equivalent rights ("DERs") until issuance.
In connection with the phantom unit awards, the CNG Committee also granted tandem DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the settlement date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.
During the year ended December 31, 2023, the Partnership granted service, performance and market-based awards under its 2017 Long-Term Incentive Plan and during the years ended December 31, 2022 and 2021, the Partnership granted service-based awards. The Partnership's service and performance-based awards granted in 2021, 2020 and 2019 wereare valued usingat the closing price of NRP's units as of the grant date.date while the Partnership's market-based awards are valued using a Monte Carlo simulation. The grant date fair value of these awards granted during the year ended December 31, 2021, 20202023, 2022 and 20192021 were $3.8$16.0 million, $3.5which included a grant-date fair value of $2.8 million for the market-based awards valued using a Monte Carlo simulation, $7.9 million and $5.4$3.8 million, respectively. Total unit-based compensation expense associated with these awards was $4.0$10.9 million,$3.6 $5.8 million and $2.4$4.0 million for the year ended December 31, 2021, 20202023, 2022 and 2019,2021, respectively, and is included in general and administrative expenses and operating and maintenance expenses on the Partnership's Consolidated Statements of Comprehensive Income (Loss).Income. The unamortized cost associated with unvested outstanding awards as of December 31, 20212023 is $3.3$13.3 million, which is towill be recognized over a weighted average period of 1.71.9 years. The unamortized cost associated with unvested outstanding awards as of December 31, 20202022 was $3.7$6.3 million.
A summary of the unit activity in the outstanding grants during 20212023 is as follows:
(In thousands) | Common Units | Weighted Average Grant Date Fair value per Common Unit | ||||||
Outstanding grants at January 1, 2023 | 386 | $ | 28.96 | |||||
Granted | 281 | $ | 56.84 | |||||
Fully vested and issued | (184 | ) | $ | 26.30 | ||||
Outstanding at December 31, 2023 | 483 | $ | 46.21 | |||||
| (In thousands) | Common Units | Weighted Average Grant Date Fair value per Common Unit | |||||||||
| Outstanding grants at January 1, 2021 | 355 | $ | 26.20 | ||||||||
| Granted | 219 | $ | 17.31 | ||||||||
| Fully vested and issued | (129) | $ | 21.38 | ||||||||
| Forfeitures | (34) | $ | 26.00 | ||||||||
| Outstanding at December 31, 2021 | 411 | $ | 23.00 | ||||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
The Partnership owns rail loadout and associated infrastructure at the Sugar Camp mine in the Illinois Basin operated by a subsidiary of Foresight. The infrastructure at the Sugar Camp mine is leased to a subsidiary of Foresight and is accounted for as a financing transaction (the "Sugar Camp lease"). The Sugar Camp lease expires in 2032 with renewal options for up to 80 additional years. Minimum payments are $5.0$5.0 million per year through the end of the lease term. The $5.0 million due to the Partnership in 2020 and 2021 is was included in the fixed cash payments from Foresight resulting from contract modifications entered into during the second quarter of 2020 as discussed in
The Partnership is exposed to credit losses through the collection of its trade receivables resulting from contracts with customers and a long-term receivable resulting from a financing transaction with a customer. The Partnership records an allowance for current expected credit losses on these receivables based on the loss-rate method. NRP assessed the likelihood of collection of its receivables utilizing historical loss rates, current market conditions that included the estimated impact of the global COVID-19COVID-19 pandemic, industry and macroeconomic factors, reasonable and supportable forecasts and facts or circumstances of individual customers and properties. Examples of these facts or circumstances include, but are not limited to, contract disputes or renegotiations with the customer and evaluation of short and long-term economic viability of the contracted property. For its long-term contract receivable, management reverts to the historical loss experience immediately after the reasonable and supportable forecast period ends.
As of December 31, 2021 2023 and 2020,2022, NRP recorded the following current expected credit loss (“CECL”) related to its receivables and long-term contract receivable:
| December 31, | ||||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||||||||||||||||
| (In thousands) | Gross | CECL Allowance | Net | Gross | CECL Allowance | Net | ||||||||||||||||||||||||||||||||
| Receivables | $ | 28,869 | $ | (3,312) | $ | 25,557 | $ | 18,512 | $ | (2,358) | $ | 16,154 | ||||||||||||||||||||||||||
| Long-term contract receivable | 32,497 | (1,126) | 31,371 | 34,818 | (1,554) | 33,264 | ||||||||||||||||||||||||||||||||
| Total | $ | 61,366 | $ | (4,438) | $ | 56,928 | $ | 53,330 | $ | (3,912) | $ | 49,418 | ||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2023 | 2022 | |||||||||||||||||||||||
(In thousands) | Gross | CECL Allowance | Net | Gross | CECL Allowance | Net | ||||||||||||||||||
Receivables | $ | 47,170 | $ | (5,655 | ) | $ | 41,515 | $ | 47,237 | $ | (4,461 | ) | $ | 42,776 | ||||||||||
Long-term contract receivable | 27,265 | (944 | ) | 26,321 | 29,984 | (1,038 | ) | 28,946 | ||||||||||||||||
Total | $ | 74,435 | $ | (6,599 | ) | $ | 67,836 | $ | 77,221 | $ | (5,499 | ) | $ | 71,722 | ||||||||||
NRP recorded $0.5$1.1 million, $1.1 million and $0.0$0.5 million in operating and maintenance expenses on its Consolidated Statements of Comprehensive Income (Loss) related to the change in the CECL allowance during the year ended December 31, 20212023, 2022 and 2020,2021, respectively.
NRP has procedures in place to monitor its ongoing credit exposure through timely review of counterparty balances against contract terms and due dates, account and financing receivable reconciliations, bankruptcy monitoring, lessee audits and dispute resolution. The Partnership may employ legal counsel or collection specialists to pursue recovery of defaulted receivables.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS—CONTINUED
19.Leases
As of December 31, 2021,2023, the Partnership had onetwo operating leaseleases for an office building that is owned by WPPLP.buildings. On January 1, 2019, the Partnership entered into a new lease offor the West Virginia office building owned by WPPLP with a five-yearfive-year base term and five additional five-yearfive-year renewal options. Upon lease commencement and as of December 31, 2021 2023 and 2020,2022, the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liability on its Consolidated Balance Sheets using the present value of the future lease payments over 30 years. On January 1, 2023, the Partnership entered into a new lease for an office building in Houston with an 11.4 year initial term and a two additional five-year renewal options. Upon lease commencement and as of December 31, 2023, the Partnership was reasonably certain to exercise all renewal options included in the lease and capitalized the right-of-use asset and corresponding lease liability on its Consolidated Balance Sheets using the present value of the future lease payments over 21.4 years. The Partnership's right-of-use asset and lease liability included within other long-term assets,, net and other non-current liabilities,, respectively, on its Consolidated Balance Sheets totaled $4.3 million and $3.5 million at both December 31, 2021 2023 and 2020.2022, respectively. During the years ended December 31, 2021, 20202023, 2022 and 2019,2021, the Partnership incurred total operating lease expenses of $0.6 million, $0.5 million and $0.5 million included in both operating and maintenance expenses and general and administrative expenses on its Consolidated Statements of Comprehensive Income (Loss)Income.
.
The following table details the maturity analysis of the Partnership's operating lease liability and reconciles the undiscounted cash flows to the operating lease liability included on its Consolidated Balance Sheet:
| Remaining Annual Lease Payments (In thousands) | December 31, 2021 | |||||||
| 2022 | $ | 483 | ||||||
| 2023 | 483 | |||||||
| 2024 | 483 | |||||||
| 2025 | 483 | |||||||
| 2026 | 483 | |||||||
| After 2026 | 10,631 | |||||||
Total lease payments (1) | $ | 13,046 | ||||||
Less: present value adjustment (2) | (9,562) | |||||||
| Total operating lease liability | $ | 3,484 | ||||||
Remaining Annual Lease Payments (In thousands) | December 31, 2023 | |||
2024 | $ | 541 | ||
2025 | 601 | |||
2026 | 604 | |||
2027 | 607 | |||
2028 | 611 | |||
After 2028 | 12,040 | |||
Total lease payments (1) | $ | 15,004 | ||
Less: present value adjustment (2) | (10,683 | ) | ||
Total operating lease liability | $ | 4,321 | ||
(1) | The remaining lease terms of the Partnership's two operating leases are 25 years and 20.4 years. |
(2) | The present value of the operating lease liability on the Partnership's Consolidated Balance Sheets was calculated using a 13.5% discount rate on the 30-year lease and a 13.4% discount rate on the 21.4 year lease. These rates represent the Partnership's estimated incremental borrowing rates under its two operating leases. As the Partnership's leases do not provide an implicit rate, the Partnership estimated the incremental borrowing rates at the time the leases were entered into by utilizing the rate of the Partnership's secured debt and adjusting it for factors that reflect the profile of borrowing over the 30-year and 21.4-year expected lease terms, respectively. | |||||||||||||
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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, 2021.2023. 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, 20212023 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, 20212023 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission "2013 Framework" (COSO). Based on that evaluation, as of December 31, 2021,2023, 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.
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, 2021,2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Natural Resource Partners L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021,2023, 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, 20212023 and 2020,2022, the related consolidated statements of comprehensive income, (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2021,2023, and the related notesand our report dated March 15, 20227, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of 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 15, 2022
During the fiscal quarter ended December 31, 2023, none of our officers or directors, as defined in Rule 16a-1(f), informed us of the adoption, modification or termination of any "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as those terms are defined in Item 408 of Regulation S-K.
ITEM 9C. DISCLSOURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
As a master limited partnership, we do not employ any of the people responsible for the management of our properties. Instead, we reimburse affiliates of our managing general partner, GP Natural Resource Partners LLC, for their services. The following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC as of the date of this Annual Report on Form 10-K. Each officer and director is elected for their respective office or directorship on an annual basis. Subject to the Board Representation and Observation Rights Agreement with Blackstone and GoldenTree, Mr. RobertsonRCM is entitled to appoint the members of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to appoint one director to Blackstone.
Name | Age | |||||||||||||
Position with the General Partner | ||||||||||||||
Corbin J. Robertson, Jr. | Chairman of the Board and Chief Executive Officer | |||||||||||||
Craig W. Nunez | President and Chief Operating Officer | |||||||||||||
Christopher J. Zolas | Chief Financial Officer | |||||||||||||
Kevin J. Craig | Executive Vice President | |||||||||||||
Philip T. Warman | General Counsel and Secretary | |||||||||||||
Gregory F. Wooten | Senior Vice President, Chief Engineer | |||||||||||||
Galdino J. Claro | Director | |||||||||||||
S. Reed Morian | Director | |||||||||||||
Paul B. Murphy, Jr. | Director | |||||||||||||
Richard A. Navarre | Director | |||||||||||||
Corbin J. Robertson, III | Director | |||||||||||||
Stephen P. Smith | Director | |||||||||||||
Leo A. Vecellio, Jr. | Director | |||||||||||||
Corbin J. Robertson, Jr.
has served as Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC since 2002. Mr. Robertson, Jr. has vast business experience having founded and served as a director and as an officer of multiple companies, both private and public, and has served on the boards of numerous non-profit organizations. He has served as the Chief Executive Officer and Chairman of the Board of the general partner of Great Northern Properties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978, as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986, and the general partner of Western Pocahontas Properties Limited Partnership since 1986. Mr. Robertson, Jr. is also Chief Executive Officer and a member of the Board of Managers of Pocahontas Royalties LLC. He also serves as a Principal with Quintana Capital Group, Chairman of the Board of the Cullen Trust for Higher Education, Chairman of the Board of KLX Energy Services Holdings, Inc. and is on the boards of the American Petroleum Institute, the National Petroleum Council, the Baylor College of Medicine and the Spirit Golf Association. In 2006, Mr. Robertson, Jr. was inducted into the Texas Business Hall of Fame. Mr. Robertson, Jr. is the father of Corbin J. Robertson, III.Craig W. Nunez
has served as President and Chief Operating Officer of GP Natural Resource Partners LLC since August 2017 and previously served as Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC from January 2015 to August 2017. Prior to joining NRP, Mr. Nunez was an owner and Chief Executive Officer of Bocage Group, a private investment company specializing in energy, natural resources and master limited partnerships since March 2012. In addition, until joining NRP, he was a FINRA-registered Investment Advisor Representative with Searle & Co since July 2012 and served as an Executive Advisor to Capital One Asset Management since January 2014. From September 2011 through March 2012, Mr. Nunez served as the Executive Vice President and Chief Financial Officer of Quicksilver Resources Canada, Inc. Mr. Nunez was Senior Vice President and Treasurer of Halliburton Company from January 2007 until September 2011, and Vice President and Treasurer of Halliburton Company from February 2006 to January 2007. Prior to that, he was Treasurer of Colonial Pipeline Company from November 1995 to February 2006. Mr. Nunez has been involved in numerous charitable organizations and currently serves on the boards of Goodwill Industries of Houston and Medical Bridges, Inc.Christopher J. Zolas
has served as Chief Financial OfficerKevin J. Craig
was named Executive Vice President of GP Natural Resource Partners LLC in February 2021, after serving as Executive Vice President, Coal of GP Natural Resource Partners LLC since September 2014. Mr. Craig was the Vice President of Business Development for GP Natural Resource Partners LLC since 2005. Mr. Craig also represents NRP as one of its appointees to the Board of Managers of Sisecam Wyoming LLC. Mr. Craig joined NRP in 2005 from CSX Transportation. He has extensive marketing, finance and operations experience within the energy industry. Mr. Craig served as a member of the West Virginia House of Delegates having been elected in 2000 and re-elected in 2002, 2004, 2006, 2008, 2010 and 2012. In addition to other leadership positions, Delegate Craig served as Chairman of the Committee on Energy. Mr. Craig did not seek re-election in 2014 and his term ended January 2015. Prior to joining CSX, he served as a Captain in the United States Army. Mr. Craig has served as the Chairman of the Huntington Regional Chamber of Commerce Board of Directors and continues as a member of both the West Virginia Chamber of Commerce and the Huntington Regional Chamber of Commerce’s respective board of directors. He serves as a member of the Board of Directors of Encova Mutual Insurance Company,Philip T. Warman
has served as General Counsel and Secretary of GP Natural Resource Partners LLC since August 2021. Mr. Warman previously served as Executive Vice President, General Counsel and Secretary of SandRidge Energy Inc. from August 2010 until June 2019. He was Associate General Counsel for SEC and finance matters for Spectra Energy Corporation from January 2007 through July 2010. From 1998 through 2006 he practiced law as a corporate finance attorney with Vinson & Elkins, LLP in Houston, Texas. Mr. Warman earned a Bachelor of Science in Chemical Engineering from the University of Houston in 1993 and graduated from the University of Texas School of Law in 1998.Gregory F. Wooten was named Senior Vice President, Chief Engineer of GP Natural Resource Partners LLC in February 2021, after serving as Vice President, Chief Engineer of GP Natural Resource Partners LLC since December 2013. Mr. Wooten joined NRP in 2007, serving as Regional Manager. Prior to joining NRP, Mr. Wooten served as Vice President, Chief Operating Officer and Chief Engineer of Dingess Rum Properties, Inc., where he managed coal, oil, gas and timber properties from 1982 until 2007. Mr. Wooten has over 35 years of experience in the coal industry, working as a planning and production engineer and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers. Mr. Wooten also serves as the President of the National Council of Coal Lessors and is a board member of the West Virginia, Kentucky, Indiana and Montana Coal Associations.Council. He also serves on the board of the Cabell-Huntington Hospital.
Galdino J. Claro
joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. Claro has 30 years of worldwide executive leadership experience in the primary and secondary metalsS. Reed Morian
joined the Board of Directors of GP Natural Resource Partners LLC in 2002. Mr. Morian has vast executive business experience having served as Chairman and Chief Executive Officer of several companies since the early 1980s and serving on the board of other companies. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian also serves on the Board of Managers of Pocahontas Royalties, LLC. Mr. Morian worked for Dixie Chemical Company from 1971 to 2006 and served as its Chairman and Chief Executive Officer from 1981 to 2006. He has also served as Chairman, Chief Executive Officer and President of DX Holding CompanyPaul B. Murphy, Jr.
joined the Board of Directors of GP Natural Resource Partners LLC in March 2018. Mr. MurphyRichard A. Navarre
joined the Board of Directors of GP Natural Resource Partners LLC in October 2013. Mr. Navarre brings extensive operating, financial, strategic planning, public company and coal industry experience to the Board of Directors. Mr. Navarre is former Chairman, President and CEO of Covia Holdings, a leading provider of high quality minerals and material solutions for the industrial and energy markets. From 1993 until 2012, Mr. Navarre heldCorbin J. Robertson, III
joined the Board of Directors of GP Natural Resource Partners LLC in May 2013. Mr. Robertson, III has experience with investments in a variety of energy businesses, having served both in management of private equity firms and having served on several boards of directors.Stephen P. Smith
joined the Board of Directors of GP Natural Resource Partners LLC in 2004. Mr. Smith brings extensive public company financial experience in the power and energy industries to the Board of Directors. Mr. Smith formerly served as Chief Financial Officer, Chief Accounting Officer and Director of the general partner of Columbia Pipeline Partners L.P. from September 2014 until June 2016. Mr. Smith also formerly served as Executive Vice President and Chief Financial Officer of Columbia Pipeline Group from July 2015 to June 2016. Mr. Smith served as Executive Vice President and Chief Financial Officer for NiSource, Inc. from August 2008 to June 2015. Prior to joining NiSource, he held several positions with American Electric Power Company, Inc, including Senior Vice President - Shared Services from January 2008 to June 2008, Senior Vice President and Treasurer from January 2004 to December 2007, and Senior Vice President - Finance from April 2003 to December 2003.Leo A. Vecellio, Jr.
joined the Board of Directors of GP Natural Resource Partners LLC in May 2007. Mr. Vecellio brings extensive experience in the aggregates and coal mine development industry to the Board of Directors. Mr. Vecellio and his family have been in the aggregates materials and construction business since the late 1930s. Since November 2002, Mr. Vecellio has served as Chairman and Chief Executive Officer of Vecellio Group, Inc, a major aggregates producer, contractor and oil terminal developer/operator in the Mid-Atlantic and Southeastern states. For nearly 30 years prior to that time Mr. Vecellio served in various capacities with Vecellio & Grogan, Inc., having most recently served as Chairman and Chief Executive Officer from April 1996 to November 2002. Mr. Vecellio is the former Chairman of the American Road and Transportation Builders and is a longtime member of the Florida Council of 100, as well as many other civic and charitable organizations.Board Meetings and Executive Sessions
The Board met seven times in 2021.2023. During 2021,2023, our non-management directors met in executive session several times. The presiding director was Mr. Vecellio, the Chairman of our Compensation, Nominating and Governance Committee, or CNG Committee. In addition, our independent directors met several times in executive session in 2021.2023. Mr. Vecellio was the presiding director at those meetings. Interested parties may communicate with our non
The Board of Directors has affirmatively determined that Messrs. Claro, Navarre, Smith, and Vecellio are independent based on all facts and circumstances considered by the Board, including the standards set forth in Section 303A.02(a) of the NYSE’s listing standards. Because we are a limited partnership as defined in Section 303A of the NYSE’s listing standards, we are not required to have a majority of independent directors on the Board. The Board has an Audit Committee, a Compensation, Nominating and Governance Committee, and a Conflicts Committee, each of which is staffed solely by independent directors.
Audit Committee
Our Audit Committee is comprised of Mr. Smith, who serves as chairman, Mr. Claro and Mr. Navarre. Mr. Smith and Mr. Navarre are "Audit Committee Financial Experts" as determined pursuant to Item 407 of Regulation S-K. During 2021,2023, the Audit Committee met
Report of the Audit Committee
Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements of the New York Stock Exchange. The Audit Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements. The Audit Committee Charter is available on our website at
www.nrplp.com and is available in print upon request.During 2021,2023, at each of its meetings, the Audit Committee met with the senior members of our financial management team, our general counsel and our independent auditors. The Audit Committee had private sessions at certain of its meetings with our independent auditors and the senior members of our financial management team and the general counsel at which candid discussions of financial management, accounting and internal control and legal issues took place.
The Audit Committee approved the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 20212023 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our financial reporting.
Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference for conservative policies when a range of accounting options is available.
The Audit Committee has discussed with the independent auditors the matters required to be discussed by the applicable requirements of the Public Company Accounting Oversight Board (“PCAOB”) and the Commission. The Audit Committee has received the written disclosures and the letter from the independent accountant required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the Audit Committee concerning independence, and has discussed with the independent accountant the independent accountant’s independence.
In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Audit Committee reviews our Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K prior to filing with the Securities and Exchange Commission. In 2021,2023, the Audit Committee also reviewed quarterly earnings announcements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Audit Committee relies on the work and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report, express an opinion on the conformity of our annual financial statements with U.S. generally accepted accounting principles.
In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, and the Board has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2021,2023, for filing with the Securities and Exchange Commission.
Stephen P. Smith, Chairman | ||||||||||||||||||
Galdino J. Claro | ||||||||||||||||||
Richard A. Navarre | ||||||||||||||||||
Executive officer compensation is administered by the CNG Committee, which is currently comprised o
• | reviewing and approving the compensation for our executive officers in light of the time that each executive officer allocates to our business; |
• | reviewing and recommending the annual and long-term incentive plans in which our executive officers participate and approving awards thereunder; and |
• | reviewing and approving compensation for the Board of Directors. |
Our Board of Directors has determined that each CNG Committee member is independent under the listing standards of the NYSE and the rules of the SEC.
Pursuant to its charter, the CNG Committee is authorized to obtain at NRP’s expense compensation surveys, reports on the design and implementation of compensation programs for directors and executive officers and other data that the CNG Committee considers as appropriate. In addition, the CNG Committee has the sole authority to retain and terminate any outside counsel or other experts or consultants engaged to assist it in the evaluation of compensation of our directors and executive officers. The CNG Committee Charter is available in print upon request.
Partnership Agreement
Investors may view our partnership agreement and the amendments to the partnership agreement on our website at
www.nrplp.com. The partnership agreement is also filed with the SEC and is available in print to any unitholder that requests them.Corporate Governance Guidelines and Code of Business Conduct and Ethics
We have adopted Corporate Governance Guidelines. We have also adopted a Code of Business Conduct and Ethics that applies to our management, and complies with Item 406 of Regulation S-K. Our Corporate Governance Guidelines and our Code of Business Conduct and Ethics are available on our website at
www.nrplp.com and are available in print upon request.NYSE Certification
Pursuant to Section 303A of the NYSE Listed Company Manual, in 2021,2023, Corbin J. Robertson, Jr. certified to the NYSE that he was not aware of any violation by the Partnership of NYSE corporate governance listing standards.
Compensation Discussion and we have elected to provide our executive compensation disclosure in accordance with such rules. Accordingly, we have provided compensation disclosure for our principal executive officer and the two most highly compensated executive officers other than our principal executive officer and have omitted the compensation discussion and analysis and the compensation committee reports as permitted by the rules.
| Name and Principal Position | Year | Salary ($) | Bonus ($) | Stock Awards ($) (1) | All Other Compensation ($) (2) | Total ($) | ||||||||||||||||||||||||||||||||||||||
| Corbin J. Robertson, Jr.—Chief Executive Officer | ||||||||||||||||||||||||||||||||||||||||||||
| 2021 | — | 2,037,340 | 946,909 | — | 2,984,249 | |||||||||||||||||||||||||||||||||||||||
| 2020 | — | 825,188 | 1,210,467 | — | 2,035,655 | |||||||||||||||||||||||||||||||||||||||
| Craig W. Nunez—President and Chief Operating Officer | ||||||||||||||||||||||||||||||||||||||||||||
| 2021 | 515,000 | 885,800 | 717,032 | 17,400 | 2,135,232 | |||||||||||||||||||||||||||||||||||||||
| 2020 | 515,000 | 358,778 | 657,866 | 17,100 | 1,548,744 | |||||||||||||||||||||||||||||||||||||||
| Christopher J. Zolas—Chief Financial Officer | ||||||||||||||||||||||||||||||||||||||||||||
| 2021 | 365,000 | 502,240 | 412,549 | 17,400 | 1,297,189 | |||||||||||||||||||||||||||||||||||||||
| 2020 | 365,000 | 203,423 | 276,989 | 17,100 | 862,512 | |||||||||||||||||||||||||||||||||||||||
Overview
As a publicly traded partnership, we have a unique employment and compensation structure that is different from that of a typical public corporation. Our named executive officers are based in Houston, Texas andare employed by Quintana Minerals Corporation (“Quintana”), and our executive officers based in Huntington, West Virginia are employed by Western Pocahontas Properties Limited Partnership (“Western Pocahontas”). Quintana isand Western Pocahontas are controlled by our Chairman and Chief Executive Officer and is an affiliateare affiliates of NRP. While our named executive officers are employed by an affiliateaffiliates of NRP, each of them has been appointed to serve as an executive officer of GP Natural Resource Partners LLC (“GP LLC”), the general partner of NRP (GP) LLC (“NRP GP”), the general partner of NRP. For a more detailed description of our structure, see "
Although our executive officers’ salaries and bonuses are paid directly by the private companies that employ them, we reimburse those companies based on the time allocated to NRP by each executive officer. Our reimbursement for the compensation of executive officers is governed by our partnership agreement. For purposes of this Compensation Discussion and Analysis, our “named executive officers” are:
• | Corbin J. Robertson, Jr.—Chairman and Chief Executive Officer |
• | Craig W. Nunez—President and Chief Operating Officer |
• | Christopher J. Zolas—Chief Financial Officer |
• | Philip T. Warman—General Counsel and Secretary |
| • | Kevin J. Craig—Executive Vice President |
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of enabling our general partner to receive distributions.
Named Executive Officer Compensation Strategy and Philosophy
Under our partnership agreement, each quarter we are required to distribute all of our available cash, as such term is defined in our partnership agreement. The Board of Directors considers numerous factors each quarter in determining cash distributions including profitability, cash flow, debt service obligations, market conditions and outlook, estimated unitholder income tax liability, and the level of cash reserves that the board determines are necessary for future operating and capital needs. Our primary objective over the last eight years has been to use all internally generated cash flow to reduce debt while paying distributions to common unitholders sufficient to cover income tax liability on their share of the partnership’s taxable income. Our compensation philosophy is designed to attract, motivate and retain highly talented executives, while keeping them focused on promoting our strategic objectives to manage the business under current market conditions and position the partnership as a key beneficiary of the transitional energy economy of the future. Our objective in determining the compensation of our named executive officers is to incentivize them to create long-term value for our unitholders and other stakeholders. We believe our compensation programs encourage sustained long-term profitability by making a portion of each named executive officer’s total direct compensation variable and dependent on our achievement of safety, financial and strategic performance goals as well as the total unitholder return of our common units. Thus, a significant portion of our executives’ total compensation is performance-based and not guaranteed, as further described under “—Components of Compensation.”
Although we reimburse Quintana and Western Pocahontas, as applicable, for the applicable portion of our named executive officers’ compensation, the CNG Committee is responsible for administering our executive officer compensation programs. To help retain and motivate executives, the CNG Committee aims to offer competitive compensation packages through a mix of cash and long-term, equity-based incentives. The CNG Committee does not have any formal policies for allocating total compensation among the various components. Instead, the CNG Committee uses its judgment, in consultation with the independent compensation consultant, to establish an appropriate balance of short-term and long-term compensation for such named executive officers for their services to us. The balance may change from year to year based on the amount of time an executive spends in service to us, our corporate strategy, financial performance and non-financial objectives, among other considerations.
Summary of Compensation Practices
We strive to maintain judicious governance standards and compensation practices by regularly reviewing best practices. The CNG Committee incorporated many best practices when forming our 2023 compensation program, including the following:
What We Do
| ✔ | Align our executive compensation with long-term performance |
✔ | Align executive officers’ interests with those of unitholders |
✔ | Engage an independent compensation consultant, NFP Compensation Consultants ("NFP"), to assess our practices |
✔ | Maintain trading policies that restrict all employees and directors from pledging or short selling our securities, entering into any derivative transactions with respect to our securities, or otherwise hedging the risk and reward of our securities |
✔ | Review the independence of any compensation consultant that is engaged to assist in our compensation analysis |
✔ | Provide limited perquisites |
What We Don’t Do
✘ | Automatically increase salaries each year or make lock-step changes in compensation based on peer group compensation levels or metrics |
✘ | Pay guaranteed or multi-year cash bonuses |
✘ | Provide significant perquisites |
✘ | Provide tax gross-ups |
The 2023 compensation for executive officers consisted of four primary components:
| • | base salaries; |
| • | short-term cash incentive compensation; |
| • | long-term equity incentive compensation; and |
| • | perquisites and other benefits. |
Mr. Robertson does not receive a salary in his capacity as Chief Executive Officer. Mr. Robertson is compensated through short-term cash and long-term equity incentive awards, all of which is allocated to NRP. To the extent our named executive officers spend time on non-NRP matters, NRP bears only the proportionate cost of their base salaries, short-term cash incentive compensation and perquisites and other benefits.
In February of each year, the CNG Committee approves the short-term cash incentive awards for the year just ended and long-term incentive awards for the named executive officers. The CNG Committee considers the performance of the partnership, the performance of the individuals and the outlook for the future in determining the amounts of the awards.
Each February, the CNG Committee also makes awards of equity-based awards to be settled in common units under the Natural Resource Partners 2017 Long-Term Incentive Plan (the “2017 Plan”) to NRP’s officers in order to incentivize management and align the long-term interests of management and NRP unitholders.
Role of the CNG Committee
The CNG Committee oversees our executive compensation and employee benefit programs, and reviews and approves all compensation decisions relating to our named executive officers and directors. The CNG Committee also approves its report for inclusion in this Annual Report and has reviewed and discussed this Compensation Discussion and Analysis with management.
Specifically, the CNG Committee reviews and approves the compensation for our named executive officers. It reviews and approves the annual and long-term incentive plans in which our named executive officers participate, and it also reviews and approves compensation programs for the members of the Board of Directors, as described further below.
Role of Independent Compensation Consultant and Market Data
The CNG Committee engaged NFP to review our compensation practices for our named executive officers and directors relative to our peers. NFP provides no services to management or the CNG Committee that are unrelated to the duties and responsibilities of the CNG Committee, and the CNG Committee makes all decisions regarding the compensation of our named executive officers and directors. NFP reports directly to the CNG Committee, and all work conducted by NFP for us is on behalf of the CNG Committee. The CNG Committee has determined that no conflicts of interest exist as a result of the engagement of NFP.
The CNG Committee, with input from NFP, selected our peer group (the “Peer Group”) after reviewing annual revenue, market capitalization, total enterprise value and total assets of relevant public companies to determine which companies were representative of the marketplace for talent within which we compete. The CNG Committee reviews the Peer Group annually to ensure continued appropriateness for comparative purposes. The CNG Committee determined that the companies below reflect an appropriate Peer Group for 2023:
Amplify Energy Corp. | Enviva Partners, LP | Ring Energy, Inc. |
| Berry Corporation | Falcon Minerals Corporation | SilverBow Resources, Inc. |
| Black Stone Minerals, L.P. | Kimbell Royalty Partners, LP | Sisecam Resources LP |
| Brigham Minerals, Inc. | NACCO Industries, Inc. | Smart Sand, Inc. |
| CatchMark Timber Trust, Inc. | PHX Minerals, Inc. | SunCoke Energy, Inc. |
| CONSOL Coal Resources LP | Ramaco Resources, Inc. | W&T Offshore Inc. |
| Earthstone Energy Inc. | Ranger Oil Corporation |
NFP provides the CNG Committee with Peer Group data for comparison purposes, such as to compare equity and pay mix practices. Market pay levels are one of multiple factors considered by the CNG Committee in setting applicable compensation amounts and determining the appropriate design of incentive compensation programs.
Role of Our Executive Officers in the Compensation Process
With respect to 2023 salaries, short-term cash incentive awards and long-term equity incentive awards, Mr. Nunez, our President and Chief Operating Officer, provided Mr. Robertson with recommendations relating to the executive officers other than himself. Mr. Robertson considered those recommendations and provided the CNG Committee with recommendations for all of the executive officers other than himself. Messrs. Robertson and Nunez considered the factors described elsewhere in this Compensation Discussion and Analysis in recommending, in their discretion, the appropriate amounts of compensation for each named executive officer (other than for themselves). Messrs. Robertson and Nunez attended the CNG Committee meetings, other than executive sessions called by the CNG Committee, at which the CNG Committee deliberated and approved the salaries, short-term cash incentive awards and long-term equity incentive awards for 2023. Messrs. Robertson and Nunez were excused from the meetings when the CNG Committee discussed their compensation.
Components of Compensation
Base Salaries
With the exception of Mr. Robertson, who does not receive a salary for his services as Chief Executive Officer, our named executive officers are paid an annual base salary by Quintana or Western Pocahontas for services rendered to us by the named executive officers during the fiscal year. We then reimburse Quintana and Western Pocahontas based on the time allocated to our business by each named executive officer to our business.officer. The base salaries of our named executive officers are reviewed on an annual basis as well as at the time of a promotion or other material change in responsibilities.
Short-Term Cash Incentive Compensation
Short-term cash incentive awards are determined based on the Partnership meeting and exceeding certain annual financial, strategic objectives and safety goals. Short-term cash incentive awards are used to motivate and reward our named executive officers. Each named executive officer received a discretionary short-term cash incentive award approved in February 20222024 by the CNG Committee. WithThe amounts awarded with respect to 2021,2023 under this program are disclosed in the Summary Compensation Table under the Bonus column. The CNG Committee, using recommendations from its independent compensation consultant, Longnecker & Associates,NFP, determined that cash bonuses would be paid based on a percentage of base salary. salary, with our Chief Executive Officer receiving approximately 2.3 times the amount awarded to the President and Chief Operating Officer for 2023. The CNG Committee used free cash flow, strategic objectives and safety as performance measures in determining the amount of bonuses paid under the plan, representing 75%, 20% and 5% of the total award, respectively. Based on the level of achievement of the performance measures, the CNG Committee used its discretion to set the level of bonus payments as a percentage of target.
The following table shows the performance measures used in the 2023 short-term cash incentive compensation for our named executive officers, together with the percentage of the total annual cash incentive grant that such component comprises. Each of the components for the named executive officers is described in greater detail below:
Performance Measure | 2023 Portion of Total Target Award | |
Free Cash Flow | 75% | |
Strategic Objectives | 20% | |
Safety | 5% |
We believe that these performance measures align our short-term incentive compensation with both unitholder and employee interests by targeting specific performance goals set forth in the first quarter of each year. By identifying meaningful performance measures, and by assigning greater weight to certain measures, we are able to more closely align compensation to the achievement of those business objectives over which particular employees have the greatest impact.
If the target level of performance is achieved with respect to a particular performance measure, the applicable payout percentage for that performance measure will equal 100%. Achievement at the threshold performance level results in a payout percentage for that performance measure that will equal 50%. If the maximum level of performance is achieved with respect to a particular performance measure the payout percentage for that measure will equal 200% of target performance, with the exception of safety which is capped at 100%. We interpolate payouts under the annual cash incentive awards for performance levels that fall between the threshold, target and maximum performance levels. There is no payout for performance that does not meet the threshold level criteria and there is no payout in excess of the maximum performance level.
Free Cash Flow
“Free Cash Flow” is calculated as cash flow from operating activities plus return on long-term contract receivable less cash flow used in investing activities, excluding proceeds from asset sales. The CNG Committee utilized the budget approved by the Board of Directors during the annual review process and set the “target” level for this performance measure at 100% of budget. The threshold payout value was set at 80% of the Free Cash Flow budget and the maximum payout value was set at 120% of the budget. We consider this performance measure to be difficult to attain and appropriately reflective of our position in the inherently volatile commodities market. The following table shows the threshold, target and maximum levels for the 2023 short-term cash incentive compensation plan:
Performance Measure | Threshold | Target | Maximum | |||
Free Cash Flow | $205,120,000 | $256,400,000 | $307,680,000 |
Strategic Objectives
Strategic Objectives are approved by the Board of Directors each year and reflect the broad strategic objectives of the partnership, which may change year to year. The measure of performance of these strategic objectives is evaluated annually by the CNG Committee and the threshold, target and maximum payouts are at the discretion of the CNG Committee.
Safety
Safety is an important emphasis for the Partnership and, the Board of Directors believes, each of the Partnership's stakeholders. Strong safety performance leads to improved employee performance and lower costs associated with regulatory citations, insurance and litigation matters, which in turn lead to improved operating performance. Because of these factors, the CNG Committee uses Reportable Injuries and Lost Time Incidents as a component of the annual incentive compensation plan. Due to the non-operating nature of our business, the “Reportable Injuries and Lost Time Incidents” are set at a target of zero, with threshold or maximum measure. Additionally, the CNG Committee considers the Partnership's completion rate for annual safety trainings with a 100% employee completion rate.
2023 Payout Under the Short-Term Cash Incentive Compensation Plan
In addition,early 2024, the CNG Committee evaluated the levels of achievement of the various performance measures for 2023 and made the following determinations:
Performance Measure | Actual Performance | Applicable Payout Percentage | Relative Weighting | Weighted Payout Percentage | ||||
Free Cash Flow | $313,400,000 | 200% | 75% | 150% | ||||
Strategic Objectives | Board Satisfaction | 150% | 20% | 30% | ||||
Safety | 100% | 100% | 5% | 5% |
Based on the actual performance as set forth above, the cumulative amounts listed below were earned under the 2023 short-term cash incentive compensation for the Partnership's 2023 performance.
Name | Target as a % of Base Salary | Actual payout as a % of Base Salary | Dollar Amount of Actual payout ($) | |||
Corbin J. Robertson, Jr. (1) | 2.3x | 2.3x | 2,369,918 | |||
Craig Nunez | 100% | 185% | 1,030,400 | |||
Christopher J. Zolas | 80% | 148% | 584,226 | |||
Philip Warman | 76% | 141% | 555,015 | |||
Kevin Craig (2) | 80% | 148% | 500,034 |
(1) | As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s actual payout. |
| (2) | Mr. Craig allocated approximately 88% of his time to NRP during the year ended December 31, 2023, and the amount of short-term cash incentive compensation reflects this allocation. |
The following table shows the target opportunities available to the named executive officers as a percentage of base salary and the actual payouts as a percentage of their base salaries for each of the last three years:
| | 2021 | 2022 | 2023 | ||||||||
Name | Target as % of Base Salary | Actual Payout as % of Target | Target as % of Base Salary | Actual Payout as % of Target | Target as % of Base Salary | Actual Payout as % of Target | ||||||
Corbin J. Robertson, Jr. (1) | 2.3x | 172% | 2.3x | 195% | 2.3x | 185% | ||||||
Craig Nunez | 100% | 172% | 100% | 195% | 100% | 185% | ||||||
Christopher J. Zolas | 80% | 172% | 80% | 195% | 80% | 185% | ||||||
Philip Warman | 76% | 172% | 76% | 195% | 76% | 185% | ||||||
Kevin Craig | 80% | 172% | 80% | 195% | 80% | 185% | ||||||
(1) | As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s actual payout. |
Long-Term Equity Incentive Compensation
We have adopted the 2017 Plan pursuant to which we may grant equity-based compensation to our named executive officers and other officers. Our CNG Committee believes that awards under the 2017 Plan promote the alignment of the interests of management with those of our unitholders and promote creation of value for our unitholders. In 2023, the CNG Committee determined it was appropriate to introduce additional performance measures in connection with long-term compensation to better align executive compensation with the Partnership's performance. We refer to these phantom units issued in 2023 as “2017 Plan Phantom Units.” The 2023 awards were made in the form of phantom units that it would considerwill settle in NRP common units on a one-for-one basis and will accrue tandem distribution equivalent rights (“DERs”) to be paid in cash upon settlement.
2023 Annual Grants
The first award of the 2017 Plan Phantom Units granted in February 2023 (“2022 Award”) was to recognize the Partnership's performance in 2022, whereby we achieved 180% of target. In determining the award amounts the CNG Committee used the following key metrics: safety, free cash flow and certain criteriastrategic initiatives. These phantom unit awards time-vest ratably over a three-year period following the grant date. The second of the 2017 Plan Phantom Units award granted in February 2023 (“2023 Award”) was to determine bonus amounts, butprovide a revised form of performance-based long-term incentive compensation. This new form included a mix of time-based and performance-based phantom units awarded at target; 35% are time-based phantom units that the criteria utilizedwill vest ratably over a three-year period and 65% are performance-based phantom units that will cliff vest at the timeend of determination, as well asthe three-year period with the actual number of units vesting for the performance-based phantom units to be determined by the performance score. The performance score will be the relative weighttotal unit holder return (“TUR”) performance score and the financial performance score, both weighted at 50%. The 2017 Plan Phantom Units (the 2022 Award and 2023 Award) are subject to forfeiture and will vest on an accelerated basis following death or disability of those criteria,the award recipient, following a change in control of NRP, or termination without cause or for good reason. The grant date fair value of the 2017 Plan Phantom Units awarded in 2023 (the 2022 Award and 2023 Award) is disclosed in the Summary Compensation Table under the Stock Awards column. In determining the award amounts the CNG Committee used a percentage target of base salary.
The following table sets forth the long-term equity award targets and number of units granted to each NEO in 2023:
2022 Award | 2023 Award | |||||||||
Named Executive Officer | Target as % of Base Salary | Time-Based | Target as % of Base Salary | Time-Based | Performance-Based | |||||
Corbin J. Robertson, Jr. (1) | 1.84x | 65,791 | 1.84x | 15,866 | 29,466 | |||||
Craig W. Nunez | 224% | 35,756 | 224% | 8,623 | 16,014 | |||||
Christopher J. Zolas | 153% | 15,071 | 153% | 4,173 | 7,751 | |||||
Philip T. Warman | 85% | 10,137 | 85% | 2,311 | 4,292 | |||||
Kevin J. Craig (2) | 90% | 10,378 | 90% | 2,380 | 4,420 | |||||
(1) | As Mr. Robertson does not receive a salary, his annual cash incentive is calculated as a multiple of the President and Chief Operating Officer’s actual payout. |
| (2) | Although Mr. Craig allocated approximately 88% of his time to NRP during the year ended December 31, 2023, the grants under the 2017 Plan to Mr. Craig do not factor in such allocation. |
Relative Total Unitholder Return Performance Score
For the relative TUR performance score, the performance-based phantom units will be eligible to vest based on the Partnership's TUR relative to the Partnership's performance peer group over the three-year performance period. The TUR calculation will be based on a “point-to-point” approach using the 20 calendar-day volume-weighted average of the closing price per share (or unit) of the Partnership or a member of the performance peer group listed below at the beginning and end of the performance period. In the event that our TUR is negative, the payout will be capped at target, regardless of peer group performance. In the instance of a merger or acquisition of a peer company during the performance period, the company would be generally discretionaryremoved from the peer group. The performance peer group for the 2023 Awards consists of the following companies:
Alliance Resource Partners | Peabody Energy Corporation |
| Alpha Metallurgical Resources | Ramaco Resources, Inc. |
| Arch Resources, Inc | Sisecam Resources LP |
| CONSOL Coal Resources LP | SunCoke Energy, Inc. |
| Corsa Coal Corp. | Warrior Met Coal, Inc |
| Enviva Inc. |
If the target level of performance is achieved, the payout percentage will equal 100%. Achievement at the threshold performance level will result in a payout at 50% of target performance and subject to changeachievement at the maximum performance level will result in a payout at 200% of target performance. We interpolate payouts for performance levels that fall between the stated performance levels. There is no payout for performance that does not meet the threshold level and there is no payout in excess of the maximum performance level. The following table shows the performance levels for the 2023 long-term performance-based equity awards:
Performance Measure | Threshold | Target | Maximum | |||
Relative Total Unitholder Return | | 18th Percentile | 45th Percentile | | 91st Percentile |
Financial Performance Score
The financial performance score is calculated based on developments atcumulative three-year free cash flow. “Free Cash Flow” is defined as cash from operating activities plus return on long-term contract receivable less cash flow used in investing activities, excluding proceeds from asset sales. Payouts will be determined based on the Partnership.
Both Quintana maintainsand Western Pocahontas maintain employee benefit plans that provide our named executive officers and other employees with the opportunity to enroll in health, dental and life insurance plans. Each of these benefit plans requirerequires the employee to pay a portion of the health and dental premiums, with the applicable company paying the remainder. These benefits are offered on the same basis to all employees of Quintana and Western Pocahontas, and the company costs are reimbursed by us to the extent the employee allocates time to our business.
In 2021,2023, Quintana and Western Pocahontas maintained tax-qualified 401(k) plans. During 2021,2023, Quintana and Western Pocahontas matched 100% of the first 6.0% of the employee contributions under their respective 401(k) plans. As with the other contributions, any amounts contributed by Quintana and Western Pocahontas are reimbursed by us based on the time allocated by the employee to our business. NeitherNone of NRP, nor Quintana or Western Pocahontas maintains a pension plan, or a defined benefit retirement plan.
Other Compensation Policies and Practices
Unit Ownership Requirements
NRP maintains Unit Ownership and Retention Guidelines (the “ownership guidelines”) that are administered by the CNG Committee and require NRP’s officers who are required to file ownership reports under Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and certain other officers as designated from time-to-time by the Board or the CNG Committee to retain all common units awarded under any NRP incentive plan (net of any units withheld or sold to cover tax liabilities) until certain ownership guidelines are met. The following table sets for the ownership guidelines. There is no minimum time period required to achieve the unit ownership guidelines.
Position | Requirement | |
| Chief Executive Officer (1) | N/A | |
| President and Chief Operating Officer | 3 x Salary | |
Chief Financial Officer | 3 x Salary | |
| General Counsel and Secretary | 1.5 x Salary | |
| Executive Vice President | 2 x Salary |
(1) | Ownership guidelines due not currently apply to our Chief Executive Officer due to his substantial ownership in NRP. |
The ownership guidelines also require directors who are not officers to retain common units with a value equal to three times the amount of the annual cash retainer paid to directors. Directors are required to achieve the unit ownership guideline within five years. Until the unit ownership guideline is achieved, each director is encouraged to retain all common units awarded under any NRP incentive plan (net of any units sold to cover tax liabilities).
Units that count towards the satisfaction of the officer and director guidelines include common units held directly by the executive officer or director, common units owned indirectly by the executive officer or director (e.g., by a spouse or other immediate family member residing in Controlthe same household or a trust for the benefit of the executive officer or director or his or her family), units granted under NRP’s long-term incentive plans (including phantom units representing the right to receive units), and units purchased in the open market (whether purchased before or after the effective date of the ownership guidelines).
Incentive Compensation Recoupment Policy
NRP maintains the Natural Resource Partners L.P. Incentive-Based Compensation Recoupment Policy, which is administered by the CNG Committee and intended to be compliant with the new clawback rules and regulations that went into effect during 2023. The policy authorizes the Board or committee thereof to recoup incentive compensation in the event of a restatement of financial statements due to material non-compliance with securities laws, fraud or misconduct. For more information, please see NRP's Incentive-Based Compensation Recoupment Policy attached as Exhibit 97.1 in this Annual Report on form 10-K.
Securities Trading Policy
Our insider trading policy restricts employees and directors, as well as their designees, from purchasing or selling puts or calls to sell or buy our common units, engaging in short sales with respect to our common units, buying our securities on margin or pledging our securities to secure debt or engaging in any transactions that would be deemed to be a hedging transaction involving our securities.
Risk Assessment of Compensation Plans
We believe that our compensation program does not encourage excessive or unnecessary risk taking. This is primarily due to the fact that our compensation programs and the compensation arrangements are designed to encourage our employees, including our named executive officers, to focus on both short-term and long-term strategic goals, thereby creating an ownership culture and helping to align the interests of our employees and our unitholders. Accordingly, our compensation program is balanced between short-term and long-term incentives, as well as cash and equity-based forms of settlement.
Overall, we believe that the balance within our compensation program results in an appropriate compensation structure and that the program does not pose risks that could have a material adverse effect on our business or financial performance.
Report of the Compensation, Nominating and Governance Committee
The CNG Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management. Based on the reviews and discussions referred to in the foregoing sentence, the CNG Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2023.
Leo A. Vecellio, Jr., Chairman
Richard A. Navarre
Stephen P. Smith
Summary Compensation Table
The following table sets forth the amounts reimbursed to affiliates of our general partner for compensation in 2021, 2022 and 2023:
Stock | All Other | ||||||||||||||||||||
Name and Principal Position (1) | Year | Salary ($) | Bonus ($) | Awards ($) (2) | Compensation ($) (3) | Total ($) | |||||||||||||||
Corbin J. Robertson, Jr.—Chief Executive Officer | |||||||||||||||||||||
2023 | — | 2,369,918 | 5,638,047 | — | 8,007,965 | ||||||||||||||||
2022 | — | 2,379,068 | 3,096,757 | — | 5,475,825 | ||||||||||||||||
2021 | — | 2,037,340 | 946,909 | — | 2,984,249 | ||||||||||||||||
Craig W. Nunez—President and Chief Operating Officer | |||||||||||||||||||||
2023 | 556,973 | 1,030,400 | 3,064,159 | 19,800 | 4,671,332 | ||||||||||||||||
2022 | 530,450 | 1,034,378 | 1,683,020 | 18,300 | 3,266,148 | ||||||||||||||||
2021 | 515,000 | 885,800 | 717,032 | 17,400 | 2,135,232 | ||||||||||||||||
Christopher J. Zolas—Chief Financial Officer | |||||||||||||||||||||
2023 | 394,748 | 584,226 | 1,369,645 | 19,800 | 2,368,419 | ||||||||||||||||
2022 | 375,950 | 586,482 | 709,414 | 18,300 | 1,690,146 | ||||||||||||||||
2021 | 365,000 | 502,240 | 412,549 | 17,400 | 1,297,189 | ||||||||||||||||
Philip T. Warman—General Counsel and Secretary (4) | |||||||||||||||||||||
2023 | 394,748 | 555,015 | 849,337 | 19,800 | 1,818,900 | ||||||||||||||||
Kevin J. Craig—Executive Vice President (5) | |||||||||||||||||||||
2023 | 337,861 | 500,034 | 871,561 | 26,243 | 1,735,699 | ||||||||||||||||
(1) | In 2023, Messrs. Robertson, Nunez, Zolas, Warman and Craig spent approximately 50%, 100%, 100%, 100% and 88%, respectively, of their time on NRP matters. |
(2) | Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see "Item 8. Financial Statements and Supplementary Data—Note 16. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K for more information. |
(3) | Includes portions of 401(k) matching allocated to Natural Resource Partners by Quintana and Western Pocahontas. |
| (4) | Mr. Warman was not a named executive officer in 2021 or 2022. |
| (5) | Mr. Craig was not a named executive officer in 2021 or 2022. Mr. Craig allocated approximately 88% of his time to NRP during the year ended December 31, 2023 and amounts included under the “Salary,” “Bonus,” and “All Other Compensation” columns reflect this allocation. Amounts included under “Stock Awards” are paid 100% by NRP. |
Grants of Plan-Based Awards in 2023
The following table shows the 2017 Plan Phantom Units granted to named executive officers during 2023. Based on the grant, the awards in the table below will either vest ratably in 2024, 2025 and 2026 or cliff vest in 2026. Upon settlement, an equivalent number of common units will be issued to each named executive officer, subject to withholding. The 2017 Plan Phantom Units also accrue DERs from the grant date, which will be paid out in cash upon settlement following and subject to vesting.
2017 Plan Phantom Units | |||||||||||||||
Estimated Future Payouts Under Equity Incentive Plan Awards (1) | All other Unit Awards (2) | ||||||||||||||
Named Executive Officer | Grant Date | Threshold (#) | Target (#) | Maximum (#) | Units (#) | Grant Date Fair Value ($) | |||||||||
Corbin J. Robertson, Jr | 2/1/2023 | 14,733 | 29,466 | 58,932 | 1,495,016 | ||||||||||
2/1/2023 | 81,657 | 4,143,031 | |||||||||||||
Craig W. Nunez | 2/1/2023 | 8,007 | 16,014 | 32,028 | 812,502 | ||||||||||
2/1/2023 | 44,379 | 2,251,657 | |||||||||||||
Christopher J. Zolas | 2/1/2023 | 3,876 | 7,751 | 15,502 | 393,262 | ||||||||||
2/1/2023 | 19,244 | 976,383 | |||||||||||||
Philip T. Warman | 2/1/2023 | 2,146 | 4,292 | 8,584 | 217,763 | ||||||||||
2/1/2023 | 12,448 | 631,574 | |||||||||||||
Kevin J. Craig | 2/1/2023 | 2,210 | 4,420 | 8,840 | 224,258 | ||||||||||
2/1/2023 | 12,758 | 647,303 | |||||||||||||
(1) | The units represent performance-based awards and cliff vest in February 2026. If threshold targets are not met, the award amount will be zero. The number of awards that vest will be between zero and the maximum. |
| (2) | The units represent time-based awards and vest ratably in February 2024, 2025 and 2026. |
Employment Agreements
None of our named executive officers have an employment agreement. All phantom units awarded under the 2017 Plan to date will vest upon a change in control
Outstanding Equity Awards at December 31, 2021
The table below shows the total
number of outstandingNamed Executive Officer | Unvested 2017 Plan Phantom Units | Market Value of Unvested 2017 Plan Phantom Units ($) (6) | ||
Corbin J. Robertson, Jr. (1) | 185,510 | 17,170,806 | ||
Craig W. Nunez (2) | 104,718 | 9,692,698 | ||
Christopher J. Zolas (3) | 47,804 | 4,424,738 | ||
Philip T. Warman (4) | 25,337 | 2,345,193 | ||
Kevin J. Craig (5) | 31,506 | 2,916,195 |
(1) | 156,044 units are time-based and vest ratably in February 2024, 2025 and 2026, and 29,466 units are performance based and cliff vest in February 2026. |
(2) | 88,704 units are time-based and vest ratably in February 2024, 2025 and 2026, and 16,014 units are performance based and cliff vest in February 2026. |
(3) | 40,053 units are time-based and vest ratably in February 2024, 2025 and 2026, and 7,751 units are performance based and cliff vest in February 2026. |
(4) | 21,045 units are time-based and vest ratably in February 2024, 2025 and 2026, and 4,292 units are performance based and cliff vest in February 2026. | ||||||||||||||||||||||
| Based on a unit price of $92.56, the closing price for the common units on December 29, 2023, the last trading day in calendar year 2023. | |||||||||||||||||||||||
Units Vested in 2023
The table below shows the value realized by each named executive officer as a result of the vesting of their phantom unit awards granted under the 2017 Plan:
Named Executive Officer | 2017 Plan Phantom Units | Value Realized on Vesting ($) (1) (2) | ||
Corbin J. Robertson, Jr. | 69,768 | 4,089,074 | ||
Craig W. Nunez | 41,816 | 2,451,874 | ||
Christopher J. Zolas | 19,743 | 1,158,139 | ||
Philip T. Warman | 1,802 | 102,858 | ||
Kevin J. Craig | 13,602 | 797,916 |
(1) | Based on a unit price of $54.08, the closing price for the common units on February 14, 2023. | |||||||||||||||||||||||||
| Includes DERs accrued from the issue date to the settlement date. | ||||||||||||||||||||||||||
Potential Payments upon Termination or Change in Control
Upon the occurrence of a change in control or termination without cause of NRP, our general partner, or GP Natural Resource Partners LLC, 2017 Plan Phantom Units held by each of our named executive officers would immediately vest and become payable and they are entitled to no other benefits because we do not have employment contracts. The table below indicates the estimated payments to each named executive officer following a change in control at December 31, 2023.
2017 Plan Equity Awards | ||||||||
Named Executive Officer | Unvested Phantom Units | Market Value ($) (1) | Accumulated DERs ($) | Total Potential Payments ($) | ||||
| Corbin J. Robertson, Jr. | 185,510 | 17,170,806 | 1,144,463 | 18,315,269 | ||||
Craig W. Nunez | 104,718 | 9,692,698 | 658,938 | 10,351,636 | ||||
Christopher J. Zolas | 47,804 | 4,424,738 | 305,789 | 4,730,527 | ||||
Philip T. Warman | 25,337 | 2,345,193 | 108,985 | 2,454,178 | ||||
Kevin J. Craig | 31,506 | 2,916,195 | 203,322 | 3,119,517 | ||||
(1) | Calculated based on a unit price of $92.56, the closing price for the common units on December 29, 2023, the last trading day in calendar year 2023. |
Directors' Compensation for the Year Ended December 31, 2021
For more information regarding the Board and committees thereof, see “
Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance” elsewhere in this Annual Report on Form 10-K. Director compensation duringThe table below shows the directors’ compensation for the year ended December 31, 2021:
| Name of Director | Fees Earned or Paid in Cash | 2017 Plan Common Unit Awards (1) | Total Compensation | |||||||||||||||||
| S. Reed Morian | $ | 75,000 | $ | 105,193 | $ | 180,193 | ||||||||||||||
Richard A. Navarre (2) | 100,000 | 105,193 | 205,193 | |||||||||||||||||
| Corbin J. Robertson, III | 75,000 | 105,193 | 180,193 | |||||||||||||||||
Stephen P. Smith (3) | 105,000 | 105,193 | 210,193 | |||||||||||||||||
| Leo A. Vecellio, Jr. | 100,000 | 105,193 | 205,193 | |||||||||||||||||
| Paul B. Murphy, Jr. | 75,000 | 105,193 | 180,193 | |||||||||||||||||
| Galdino J. Claro | 85,000 | 105,193 | 190,193 | |||||||||||||||||
Alexander D. Greene (4) | — | — | — | |||||||||||||||||
Name of Director | Fees Earned or Paid in Cash ($) | 2017 Plan Common Unit Awards ($) (1) | Total Compensation ($) | |||
S. Reed Morian | 75,000 | 115,021 | 190,021 | |||
Richard A. Navarre (2) | 110,500 | 115,021 | 225,521 | |||
Corbin J. Robertson, III | 75,000 | 115,021 | 190,021 | |||
Stephen P. Smith (3) | 110,500 | 115,021 | 225,521 | |||
Leo A. Vecellio, Jr. | 102,500 | 115,021 | 217,521 | |||
Paul B. Murphy, Jr. | 75,000 | 115,021 | 190,021 | |||
Galdino J. Claro | 88,000 | 115,021 | 203,021 |
(1) | Amounts represent the grant date fair value of phantom unit awards determined in accordance with Accounting Standards Codification Topic 718 determined without regard to forfeitures. For information regarding the assumptions used in calculating these amounts, see "Item 8. Financial Statements and Supplementary Data—Note 16. Unit-Based Compensation" elsewhere in this Annual Report on Form 10-K. All of the phantom units reported in this column were outstanding on December 31, 2023 and will vest on February 1, 2024. As of December 31, 2023, each of the current directors hold the following number of outstanding phantom unit awards: Mr. Morian, 2,267; Mr. Navarre, 6,621; Mr. Robertson, 2,267; Mr. Smith, 17,629; Mr. Vecellio, 2,267; Mr. Murphy, 2,267 and Mr. Claro, 2,267. |
(2) | ||||||||||||||
Mr. Navarre elected to defer settlement of his common units awarded under the 2017 Plan in 2018 and 2019 until 90 days following his retirement or earlier departure from the Board. As of December 31, 2023, 6,621 phantom units previously awarded to Mr. Navarre were outstanding but only 2,267 were unvested.
(3) | Mr. Smith elected to defer settlement of his common units awarded under the 2017 Plan in 2018, 2019, 2020, 2021 and 2022 until 90 days following his retirement or earlier departure from the Board. As of December 31, 2023, 17,629 phantom units previously awarded to Mr. Smith were outstanding but only 2,267 were unvested. |
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2023, Messrs. Vecellio, Navarre, and Smith served on the CNG Committee. None of Messrs. Vecellio, Navarre, and Smith has ever been an officer or employee of NRP or GP LLC. None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has any executive officer serving as a member of our Board or CNG Committee.
Pay Ratio Disclosure
The Securities and Exchange Commission has adopted a rule requiring annual disclosure of the ratio of the median employee’s total annual compensation to the total annual compensation of the principle executive officer.
The personnel providing services to us, including our executive officers, are employed by Quintana or Western Pocahontas. As of December 31, 2021, 10,431 phantom units previously awarded2023, 55 such persons were providing services to Mr. Navarre were outstanding but only 6,077 were unvested.
After identifying the median service provider based on total compensation, we calculated annual 2023 compensation for the median service provider using the same methodology used to calculate the Chief Executive Officer’s total compensation as reflected in the Blackstone designeeSummary Compensation Table above. The median service provider’s annual 2023 compensation was as follows:
Name | Year | Salary ($) | Bonus ($) | Non-Equity Incentive Plan Compensation ($) | Stock Awards ($) | All Other Compensation ($) | Total ($) | |||||||
Median Service Provider | 2023 | 101,389 | 46,893 | 34,434 | — | 6,083 | 188,799 |
Our 2023 ratio of Chief Executive Officer total compensation of $8,007,965 to the Bo
The following tables set forth, as of March 1, 2022,February 22, 2024, the amount and percentage of our common units and preferred units beneficially held by (1) each person known to us to beneficially own 5% or more of any class of our units, (2) by each of our directors and named executive officers and (3) by all directors and executive officers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the units shown.
| Name of Beneficial Owner | Common Units | Percentage of Common Units (1) | ||||||||||||
Corbin J. Robertson, Jr. (2) | 2,478,742 | 19.8 | % | |||||||||||
Western Pocahontas Corporation (3) | 1,739,007 | 13.9 | % | |||||||||||
Western Pocahontas Properties Limited Partnership (4) | 1,727,986 | 13.8 | % | |||||||||||
JPMorgan Chase & Co. (5) | 1,028,351 | 8.2 | % | |||||||||||
The Goldman Sachs Group, Inc. (6) | 1,112,356 | 8.9 | % | |||||||||||
| Craig W. Nunez | 37,755 | * | ||||||||||||
| Christopher J. Zolas | 22,259 | * | ||||||||||||
| Galdino J. Claro | 15,122 | * | ||||||||||||
| Alexander D. Greene | — | — | ||||||||||||
S. Reed Morian (7) | 631,521 | 5.0 | % | |||||||||||
| Paul B. Murphy, Jr. | 14,815 | * | ||||||||||||
Richard A. Navarre (8) | 12,008 | * | ||||||||||||
Corbin J. Robertson III (9) | 249,664 | 2.0 | % | |||||||||||
Stephen P. Smith (10) | 355 | * | ||||||||||||
| Leo A. Vecellio, Jr. | 17,362 | * | ||||||||||||
Directors and Officers as a Group (11) | 3,513,459 | 28.1 | % | |||||||||||
Percentage of | ||||||||
Common | Common | |||||||
Name of Beneficial Owner | Units | Units (1) | ||||||
Corbin J. Robertson, Jr. (2) | 2,569,048 | 19.8 | % | |||||
Quintana Management LLC (3) | 1,883,986 | 14.5 | % | |||||
The Goldman Sachs Group, Inc. (4) | 917,289 | 7.1 | % | |||||
Kevin J. Craig | 35,262 | * | ||||||
Craig W. Nunez | 89,340 | * | ||||||
Philip T. Warman | 4,557 | * | ||||||
Christopher J. Zolas | 42,234 | * | ||||||
Galdino J. Claro | 20,109 | * | ||||||
S. Reed Morian (5) | 636,508 | 4.9 | % | |||||
Paul B. Murphy, Jr. | 22,802 | * | ||||||
Richard A. Navarre (6) | 16,995 | * | ||||||
Corbin J. Robertson III (7) | 254,651 | 2.0 | % | |||||
Stephen P. Smith (8) | 2,622 | * | ||||||
Leo A. Vecellio, Jr. | 22,349 | * | ||||||
Directors and Officers as a Group (9) | 3,748,679 | 28.9 | % | |||||
* | ||||||||||||||||||
Less than one percent. | |||||
(1) | 12,960,064 common units issued and outstanding as of February 22, 2024. |
(2) | Mr. Robertson, Jr. may be deemed to beneficially own 668,748 common units owned in his capacity as controlling owner of Quintana Holdings, LP, 1,727,986 common units in his capacity as controlling member of Quintana Management LLC, which is the sole member of Western Pocahontas GP LLC, which is the general partner of Western Pocahontas Limited Partnership, 156,000 common units in his capacity as the controlling member of Quintana Management LLC, which is the sole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource Partners LLC, which is the general partner of NRP (GP) LP, 11,021 common units in his capacity as controlling shareholder of Western Pocahontas Corporation, and 5,293 common units in his capacity as controlling shareholder of GNP Management Corporation. Mr. Robertson, Jr.’s address is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. |
(3) | Quintana Management LLC has voting and dispositive power with respect to 1,727,986 common units in its capacity as sole member of Western Pocahontas GP LLC, which is the general partner of Western Pocahontas Properties Limited Partnership and 156,000 common units in its capacity as the sole member of Robertson Coal Management LLC, which is the sole member of GP Natural Resource Partners LLC, which is the general partner of NRP (GP) LP. The business address of Quintana Management LLC is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. |
(4) | According to a Schedule 13G filing with the SEC on February 7, 2024, The Goldman Sachs Group holds shared voting power and shared dispositive power with respect to 917,289 common units in the Partnership. The business address of The Goldman Sachs Group is 200 West Street, New York, NY 10282. |
(5) | Mr. Morian may be deemed to beneficially own 344,863 common units owned by Shadder Investments and 60,097 common units owned by Mocol Properties, L.P. |
(6) | Does not include 4,354 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Navarre has elected to defer settlement of until 90 days following the date that he no longer serves on NRP’s board. |
(7) | Mr. Robertson III may be deemed to beneficially own 9,783 common units held by CIII Capital Management, LLC, 10,000 common units held by BHJ Investments LP, 19,663 common units held by The Corbin James Robertson III, 2009 Family Trust and 39 common units held by his spouse, Brooke Robertson. The address for CIII Capital Management, LLC, BHJ Investments LP, and The Corbin James Robertson III, 2009 Family Trust is 1415 Louisiana Street, Suite 2400, Houston, Texas 77002. The following common units are pledged as collateral for loans: 68,873 common units owned by Mr. Robertson III. |
(8) | Does not include 18,082 common units awarded pursuant to NRP’s long-term incentive plan that Mr. Smith has elected to defer settlement of until 90 days following the date that he no longer serves on NRP’s board. Mr. Smith may be deemed to beneficially own 355 common units owned by the SP Smith 2002 Revocable Trust. |
(9) | NRP’s directors and executive officers as a group consists of 13 individuals. |
Percentage of | ||||||||
Name of Beneficial Owner | Preferred Units | Preferred Units | ||||||
GoldenTree Asset Management, LP (1) | 71,666 | 100 | % | |||||
(1) | The preferred units are owned by funds managed by GoldenTree Asset Management, LP, whose address is 300 Park Ave, New York, NY 10022. Steven A. Tananbaum serves as senior managing member of GoldenTree Asset Management LLC, the general partner of GoldenTree Asset Management, LP. |
Securities Authorized for Issuance under Equity Compensation Plans
The following table shows the securities authorized for issuance under our 2017 Long-Term Incentive Plan as of December 31, 2023. The initial number of common units owned by Shadder Investments and 60,097 common units owned by Mocol Properties.
| Name of Beneficial Owner | Preferred Units | Percentage of Preferred Units | ||||||||||||
Blackstone Inc. (1) | 142,500 | 57 | % | |||||||||||
GoldenTree Asset Management, LP (2) | 107,500 | 43 | % | |||||||||||
Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||||||
Plan Category | (a) | (b) | (c) | |||||||||
Equity compensation plans approved by security holders | — | — | 713,893 | (1) | ||||||||
Equity compensation plans not approved by security holders | n/a | n/a | n/a | |||||||||
Total | — | — | 713,893 | |||||||||
(1) | As of December 31, 2023, 483,483 2017 Plan Phantom Units were outstanding. Each 2017 Plan Phantom Units represents the right to receive one common unit, together with associated distribution equivalent rights. | |||||||||||||
Relationships with Entities Associated with Corbin J. Robertson, Jr.
Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, and Great Northern Properties Limited Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the WPP Group."WPP Group". Corbin J. Robertson, Jr. ownscontrols the general partner of Western Pocahontas Properties, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman and Chief Executive Officer of New Gauley Coal Corporation.
Omnibus Agreement
As part of the omnibus agreement entered into concurrently with the closing of our initial public offering (the "Omnibus Agreement"), the WPP Group and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the “GP affiliates,” each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a "restricted business") in the specific circumstances described below:
• | the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal within the United States; and |
• | the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal within the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate. |
"Affiliate" means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group and their respectiveits controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us.
A GP affiliate may, directly or indirectly, engage in a restricted business if:
• | the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below. |
• | the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below. |
• | the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under the procedures described below. |
• | its ownership in the restricted business consists solely of a non-controlling equity interest. |
For purposes of this paragraph, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate.
The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in by the WPP Group at closing of our initial public offering (and except as described below under "—Pocahontas Royalties LLC"), may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be acquired.
If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer us the opportunity to purchase the restricted business within six months of acquisition.
For purposes of this paragraph, "restricted business" excludes a general partner interest or managing member interest, which is addressed in a separate restriction summarized below. For purposes of this paragraph only, "fair market value" means the fair market value as determined in good faith by the relevant GP affiliate.
If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate may operate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.
If, at the end of the two yeartwo-year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will be under no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned.
In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer the restricted business to the general partner at the new fair market value, and the offer procedures described above will recommence.
If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly held limited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPP Group may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures described above.
The omnibus agreementOmnibus Agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of the WPP Group under the omnibus agreementOmnibus Agreement terminate when the WPP Group and its affiliates cease to participate in the control of the general partner.
Pocahontas Royalties LLC
On February 28, 2020, Pocahontas Royalties LLC (“Pocahontas Royalties”) completed the acquisition of a private company that owns approximately one million acres of mineral rights and leases coal to coal mine operators in Central Appalachia. Pocahontas Royalties is controlled by Corbin J. Robertson, Jr. and members of his family. Reed Morian, one of the directors of GP Natural Resource Partners LLC, also serves on the Board of Managers of Pocahontas Royalties.
In connection with the closing of the acquisition, we and Pocahontas Royalties entered into a limited waiver of the omnibus agreementOmnibus Agreement pursuant to which we waived the provision of the omnibus agreementOmnibus Agreement that restricts Mr. Robertson, Jr. and his affiliates (other than NRP) from owning, operating or investing in fee coal in the United States with an aggregate fair market value in excess of $75 million. Mr. Robertson had previously offered NRP the opportunity to participate in the acquisition and we determined, after due consideration, not to participate.
In addition, on February 28, 2020, we and Pocahontas Royalties entered into a right of first offer agreement pursuant to which Pocahontas Royalties granted us the exclusive right of first offer to purchase any assets (or entities holding such assets) proposed to be sold at any time by Pocahontas Royalties or any of its subsidiaries with a fair market value exceeding $2 million (individually or in the aggregate), excluding surface acreage, assets or rights (other than surface rights that are appurtenant to or
Preferred Unitholder Board Representation and Observation Rights Agreement
Effective on March 2, 2017, in connection with the closing of the issuance of the Preferred Units, we entered into the Board ObservationRepresentation and RepresentationObservation Rights Agreement (the “Board Rights Agreement”) with Blackstone and GoldenTree. Pursuant to the Board Rights Agreement, Blackstone appointsappointed one member to serve on the Board of Directors of GP Natural Resource Partners LLC and also appoints one observer to attend meetings of the Board.Board of Directors. Pursuant to the Board Rights Agreement, Blackstone's rights to appoint a member of the Board and an observer will terminate at such time as Blackstone, together with their affiliates, no longer own at least 20% of the total number of Preferred Unitspreferred units issued on the closing date, together with all PIK Unitsunits that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). Following the time that Blackstone (and their affiliates) no longer own the Minimum Preferred Unit Threshold and until such time as GoldenTree (together with their affiliates) no longer own the Minimum Preferred Unit Threshold, GoldenTree shall have the one-time option to appoint either one person to serve as a member of the Board of Directors or one person to serve as a Board of Directors observer. To the extent GoldenTree elects to appoint a Board of Directors member and later remove such Board member,board designee, GoldenTree may then elect to appoint a Board of Directors observer. In 2023, we repurchased all of Blackstone's preferred units, which were subsequently retired and no longer remain outstanding, and all rights of Blackstone related thereto ceased as a result. In connection with these repurchases, Blackstone's board designee resigned from the Board of Directors. GoldenTree did not exercise its one-time option pursuant to the Board Rights Agreement to appoint either a director or an observer to the Board of Directors within 30 days of receipt of notice that Blackstone (and its affiliates) no longer own the Minimum Preferred Unit Threshold and GoldenTree no longer has the right to appoint either a director or an observer to the Board of Directors. For more information on the Preferred Units, including the rights of the holders thereof, see "
Office Building in Huntington, West Virginia
We lease an office building in Huntington, West Virginia from Western Pocahontas Properties Limited Partnership. The initial 10-year term of the lease expired at the end of 2018. On January 1, 2019, we entered into a new lease on the building for a five-year base term, with five additional five-year renewal options. We paid approximatelyapproximately $0.8 million to Western Pocahontas under the lease during both yearsthe year ended December 31, 2021 and 2020.
Relationship with Cadence Bank, N.A.
Paul B. Murphy, Jr. one of the members of the Board of Directors, of GP Natural Resource Partners LLC, is the Chairman of Cadence Bank, N.A., which is a lender under NRP Operating’sOpco's revolving credit facility and has received customary fees and interest payments in connection therewith. We paid approximately $0.1$2.1 million in interest and fees under the credit facility to Cadence Bank, N.A during both yearsthe year ended December 31, 2021 and 2020.2023.
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group and Pocahontas Royalties) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLC have duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the Board of Directors of our general partner of such resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:
• | approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or course of action that has not received approval; |
• | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
• | fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement, consider:
• | the relative interests of any party to such conflict and the benefits and burdens relating to such interest; |
• | any customary or accepted industry practices or historical dealings with a particular person or entity; |
• | generally accepted accounting practices or principles; and |
• | such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. |
In addition, GoldenTree has certain limited consent rights. In the exercise of these consent rights, and board rights, conflicts of interest could arise between us on the one hand, and Blackstone or GoldenTree on the other hand.
Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
• | amount and timing of asset purchases and sales; |
• | cash expenditures; |
• | borrowings; |
• | the issuance of additional common units; and |
• | the creation, reduction or increase of mineral rights in any quarter. |
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of enabling our general partner to receive distributions.
For example, in the event we have not generated sufficient cash from our operations to pay the quarterly distribution on our common units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding common units.
The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries.
We do not have any officers or employees. We rely on officers and employees of GP Natural Resource Partners LLC and its affiliates.
We do not have any officers or employees and rely on officers and employees of GP Natural Resource Partners LLC and its affiliates. Affiliates of GP Natural Resource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource Partners LLC are not required to work full time on our affairs. Certain of these officers devote significant time to the affairs of the WPP Group or its affiliates and are compensated by these affiliates for the services rendered to them.
We reimburse our general partner and its affiliates for expenses.
We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.
Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-lengtharm’s-length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length negotiations.
All of these transactions entered into after our initial public offerings are on terms that are fair and reasonable to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
We may not choose to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
Our general partner’spartner’s affiliates may compete with us.
The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement and the Omnibus Agreement, affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us.
The Conflicts Committee Charter is available upon request.
Director Independence
For a discussion of the independence of the members of the Board of Directors of our managing general partner under applicable standards, see "
Item 10. Directors and Executive Officers of the Managing General Partner and Corporate Governance—Corporate Governance—Independence of Directors," which is incorporated by reference into this Item 13.Review, Approval or Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner and its affiliates (including the WPP Group and Pocahontas Royalties) on the one hand, and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under "—Conflicts of Interest."
Pursuant to our Code of Business Conduct and Ethics, conflicts of interest are prohibited as a matter of policy, except under guidelines approved by the Board of Directors and as provided in the Omnibus Agreement and our partnership agreement. For the year ended December 31, 20212023 there were no transactions where such guidelines were not followed.
The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended, and we engaged Ernst & Young LLP to audit our accounts and assist with tax compliance for fiscal 20212023 and 2020.2022. All of our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board of Directors. The following table presents fees for professional services rendered by Ernst & Young LLP:
| 2021 | 2020 | ||||||||||
Audit Fees (1) | $ | 757,450 | $ | 785,750 | |||||||
Tax Fees (2) | 412,500 | 505,915 | |||||||||
2023 | 2022 | |||||||
Audit Fees (1) | $ | 972,500 | $ | 904,137 | ||||
Tax Fees (2) | 442,270 | 437,400 | ||||||
(1) | Audit fees include fees associated with the annual integrated audit of our consolidated financial statements and internal controls over financial reporting, separate audits of subsidiaries and reviews of our quarterly financial statement for inclusion in our Form 10-Q and comfort letters; consents; work related to acquisitions; assistance with and review of documents filed with the SEC. |
(2) | Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1. | |||||||||||||
Audit and Non-Audit Services Pre-Approval Policy
I. Statement of Principles
Under the Sarbanes-Oxley Act of 2002 (the "Act"), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the SEC has issued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the "Policy"), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor may be pre-approved.
The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee ("general pre-approval") or require the specific pre-approval of the Audit Committee ("specific pre-approval"). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficient procedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-approval by the Audit Committee.
For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The Audit Committee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiarity with our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage or control risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative.
The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
The appendices to thisthe Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any general pre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. For the audit, pre-approval is for the fiscal year as the time between approval and the actual issuance of the audit may be more than 12 months. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will add or subtract to the list of general pre-approved services from time to time, based on subsequent determinations.
The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by the independent auditor to management.
Ernst & Young LLP, our independent auditor reviews this Policy annually and it does not adversely affect its independence.
As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Stephen P. Smith, the Chairman of the Audit Committee. Mr. Smith must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.
III. Audit Services
The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annual financial statement audit (including required quarterly reviews), subsidiary audits and other procedures required to be performed by the independent auditor to be able to form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testing performed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services also include the attestation engagement for the independent auditor’s report on internal controls for financial reporting. The Audit Committee monitors the audit services engagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in audit scope, partnership structure or other items.
In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other audit services, which are those services that only the independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits for our subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection with securities offerings.
IV. Audit-related Services
Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financial statements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does not impair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accounting consultations related to accounting, financial reporting or disclosure matters not classified as "Audit Services"; assistance with understanding and implementing new accounting and financial reporting guidance from rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal control reporting requirements.
V. Tax Services
The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advice without impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes it may grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would not impair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of the independent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officer or outside counsel to determine that the tax planning and reporting positions are consistent with this Policy.
VI. Pre-Approval Fee Levels or Budgeted Amounts
Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Any proposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overall relationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determine the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
VII. Procedures
All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submitted to the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of any such services rendered by the independent auditor.
Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the Audit Committee by both the independent auditor and the Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with the SEC’s rules on auditor independence.
(a)(1) and (2)Financial Statements and Schedules
(2) All schedules are omitted because they are not required or because the information is immaterial or provided elsewhere in the Consolidated Financial Statements and Notes thereto.
(a)(3) Sisecam Wyoming LLC Financial Statements
The financial statements of Sisecam Wyoming LLC required pursuant to Rule 3-09 of Regulation S-X are included in this filing as
Exhibit 99.1.(a)(4) Exhibits
Exhibit | Description | ||||||||||||||
Exhibit | Description | ||||||||||||||
Number 101.INS* | |||||||||||||||
Inline XBRL Instance Document | |||||||||||||||
101.SCH* | Inline XBRL Taxonomy Extension Schema Document | ||||||||||||||
101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document | ||||||||||||||
101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document | ||||||||||||||
101.LAB* | Inline XBRL Taxonomy Extension Labels Linkbase Document | ||||||||||||||
101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document | ||||||||||||||
104* | Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101) | ||||||||||||||
* | Filed herewith | ||||||||||||||
** | Furnished herewith | ||||||||||||||
+ | Management compensatory plan or arrangement | ||||||||||||||
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NATURAL RESOURCE PARTNERS L.P. | ||||||||||||||||||
By: | NRP (GP) LP, its general partner | |||||||||||||||||
By: | GP NATURAL RESOURCE | |||||||||||||||||
PARTNERS LLC, its general partner | ||||||||||||||||||
Date: March | ||||||||||||||||||
By: | /s/ CORBIN J. ROBERTSON, JR. | |||||||||||||||||
Corbin J. Robertson, Jr. | ||||||||||||||||||
Chairman of the Board, Director and | ||||||||||||||||||
Chief Executive Officer | ||||||||||||||||||
(Principal Executive Officer) | ||||||||||||||||||
Date: March | |||||||||||
By: | /s/ CHRISTOPHER J. ZOLAS | ||||||||||
Christopher J. Zolas | |||||||||||
Chief Financial Officer | |||||||||||
(Principal Financial and Accounting Officer) | |||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: March 7, 2024 | |||||||||
/ s/ GALDINO J. CLARO | |||||||||
Galdino J. Claro | |||||||||
Director | |||||||||
Date: March | |||||
/ s | |||||
S. Reed Morian | |||||
Director | |||||
Date: March | |||||
/s/ PAUL B. MURPHY, JR. | |||||
Paul B. Murphy, Jr. | |||||
Director | |||||
Date: March | |||||
/s/ RICHARD A. NAVARRE | |||||
Richard A. Navarre | |||||
Director | |||||
Date: March | |||||
/s/ CORBIN J. ROBERTSON III | |||||
Corbin J. Robertson III | |||||
Director | |||||
Date: March | |||||
/s/ STEPHEN P. SMITH | |||||
Stephen P. Smith | |||||
Director | |||||
Date: March | |||||
/s/ LEO A. VECELLIO, JR. | |||||
Leo A. Vecellio, Jr. | |||||
Director | |||||